CALGARY, ALBERTA (NYSE: CNQ):
Commenting on first quarter 2008 results, Canadian Natural's
Chairman, Allan Markin stated, "It has been a good start to the
year for Canadian Natural. We completed our winter drilling program
in advance of spring break-up, meeting our targets. Our teams were
presented with several weeks of cold weather, leading to many
weather related issues. The teams rose to the challenge and
delivered impressive results. At the Horizon Project, severe
weather conditions factored into lower productivity. As the weather
became warmer, efficiencies improved and first oil remains targeted
for the third quarter of this year."
John Langille, Vice-Chairman, stated, "First quarter cash flow
was a reflection of higher realized crude oil pricing, resulting
from a lower heavy crude oil differential. The heavy crude oil
differential improved due to reduced refinery cracking margins that
influence demand for heavy crude oil. Stronger natural gas pricing
also added to the bottom line as a cold, late winter resulted in a
draw on natural gas inventories. Natural gas pricing was also
affected by fewer liquefied natural gas imports to North America
and reduced production coming out of Canada. As a result of the
increases in both crude oil and natural gas realized strip prices,
our cash flow for the year is projected to be in balance with our
capital program. Our balance sheet should continue to strengthen as
we expect solid earnings throughout 2008."
Steve Laut, President and Chief Operating Officer of Canadian
Natural commented, "During Q1/08, we saw the continued benefits of
our high-graded natural gas drilling program with strong and steady
production delivering on budget. Our North American crude oil
drilling program also produced excellent results, particularly from
our Pelican Lake assets. Looking ahead, work at the Primrose East
Thermal Project continues on schedule, with production expected for
early 2009, a further step towards unlocking the significant value
of Canadian Natural's thermal crude oil resource base. Our
International crude oil projects are also making significant
strides with the Olowi Project in Offshore Gabon continuing on
track for first oil targeted for late 2008, along with the
mobilization of the deep water drilling rig for Baobab in Offshore
Cote d'Ivoire. The Horizon Project remains targeted for a Q3/08
start up with operations readiness on schedule to date. The year of
execution has started off extremely well."
HIGHLIGHTS
Three Months Ended
-----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions, except as noted) 2008 2007 2007
----------------------------------------------------------------------------
Net earnings $ 727 $ 798 $ 269
Per common share, basic and
diluted $ 1.35 $ 1.48 $ 0.50
Adjusted net earnings from
operations (1) $ 872 $ 546 $ 621
Per common share, basic and
diluted $ 1.61 $ 1.02 $ 1.15
Cash flow from operations (2) $ 1,725 $ 1,486 $ 1,622
Per common share, basic and
diluted $ 3.19 $ 2.75 $ 3.01
Capital expenditures, net of
dispositions $ 1,753 $ 1,514 $ 2,009
Daily production, before royalties
Natural gas (mmcf/d) 1,538 1,589 1,717
Crude oil and NGLs (bbl/d) 327,217 337,240 327,001
Equivalent production (boe/d) 583,488 601,908 613,114
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(1) Adjusted net earnings from operations is a non-GAAP measure that the
Company utilizes to evaluate its performance. The derivation of this
measure is discussed in the Management's Discussion and Analysis
("MD&A").
(2) Cash flow from operations is a non-GAAP measure that the Company
considers key as it demonstrates the Company's ability to fund capital
reinvestment and debt repayment. The derivation of this measure is
discussed in the MD&A.
- Natural gas production volumes for the first quarter
represented 44% of the Company's total production. Natural gas
production for Q1/08 averaged 1,538 mmcf/d, down 10% from 1,717
mmcf/d for Q1/07 and down 3% from 1,589 mmcf/d for Q4/07. As
expected, volumes in Q1/08 reflected a strong winter drilling
program offset by the natural decline in base production and
continued reallocation of capital towards higher return projects in
crude oil.
- Total crude oil and NGLs production for Q1/08 was 327,217
bbl/d. Q1/08 production volumes were slightly higher than Q1/07
volumes of 327,001 bbl/d, and decreased 3% from Q4/07 volumes of
337,240 bbl/d. Volumes in Q1/08 reflect the transition between
steam and production cycles for Primrose thermal wells and
continued conversion of production wells to polymer injection wells
at Pelican Lake.
- Quarterly cash flow from operations was $1.73 billion, an
increase of 6% from Q1/07 and an increase of 16% from Q4/07. The
increase from Q1/07 and Q4/07 primarily reflected higher crude oil
and natural gas realizations, partially offset by realized hedging
losses.
- Quarterly net earnings for Q1/08 were $727 million. Quarterly
adjusted net earnings from operations for Q1/08 were $872
million.
- Maintained a strong undeveloped conventional core land base in
Canada of 11.8 million net acres - a key asset for continued value
growth.
- Continued production improvements at the Pelican Lake Field
were realized from new drilling activity and the expansion of the
enhanced crude oil recovery program. Pelican Lake crude oil
production averaged approximately 37,000 bbl/d during the first
quarter of 2008, up significantly by 5,000 bbl/d from Q1/07 and up
1,000 bbl/d from Q4/07.
- The Primrose East Expansion, which is targeted to add 40,000
bbl/d of capacity, made significant progress and is targeted for
first steaming in late 2008 and production in early 2009.
- Secured a deep water drilling rig for the Baobab Field. The
equipment was mobilized in early Q2/08, enabling work to begin on
the restoration of shut-in production. It is targeted that a
minimum 3 of the 5 Baobab wells come on stream over the course of
2008 and 2009.
- The Olowi Project in Offshore Gabon continues on track. The
drilling rig has been mobilized and arrived on site in late April.
First crude oil production is targeted for Q4/08.
- Work progress on the Horizon Oil Sands Project ("Horizon
Project") exited Q1/08 at 94% complete and first oil is targeted
for Q3/08.
- Commencing January 1, 2009, the Company's commodity hedging
program has been revised by its Board of Directors to allow for the
hedging of up to 50% (currently 75%) of the near 12 months budgeted
production and up to 25% (currently 50%) of the following 13 to 24
months estimated production. The purchase of put options will
continue to be in addition to the above parameters. The Company
continues to believe that its risk management program meets its
objective of securing funding for its capital projects.
- Declared a quarterly cash dividend on common shares of C$0.10
per common share, payable July 1, 2008.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural
focuses its activities in core regions where it can dominate the
land base and infrastructure. Undeveloped land is critical to the
Company's ongoing growth and development within these core regions.
Land inventories are maintained to enable continuous exploitation
of play types and geological trends, greatly reducing overall
exploration risk. By dominating infrastructure, the Company is able
to maximize utilization of its production facilities, thereby
increasing control over production costs. Further, the Company
maintains large project inventories and production diversification
among each of the commodities it produces; namely natural gas,
light/medium and heavy crude oil and NGLs. A large diversified
project portfolio enables the effective allocation of capital to
higher return opportunities.
OPERATIONS REVIEW
Activity by core region
-----------------------------------------
Net undeveloped land
as at Drilling activity
Mar 31, 2008 three months ended
(thousands of net Mar 31, 2008
acres) (net wells) (1)
----------------------------------------------------------------------------
Canadian conventional
Northeast British Columbia 2,348 20.2
Northwest Alberta 1,451 53.3
Northern Plains 6,528 170.8
Southern Plains 920 68.3
Southeast Saskatchewan 122 10.1
In-situ Oil Sands 476 35.1
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11,845 357.8
Horizon Oil Sands Project 115 -
United Kingdom North Sea 268 1.6
Offshore West Africa 206 0.6
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12,434 360.0
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(1) Drilling activity includes stratigraphic test and service wells
Drilling activity (number of wells)
Three Months Ended Mar 31
-------------------------------------
2008 2007
Gross Net Gross Net
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Crude oil 184 173 210 193
Natural gas 191 161 246 201
Dry 13 11 68 60
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Subtotal 388 345 524 454
Stratigraphic test / service wells 15 15 234 234
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Total 403 360 758 688
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Success rate (excluding stratigraphic
test / service wells) 97% 87%
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North America Conventional
North America natural gas
Quarterly Results
---------------------------------------
Q1/08 Q4/07 Q1/07
----------------------------------------------------------------------------
Natural gas production (mmcf/d) 1,513 1,562 1,694
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Net wells targeting natural gas 167 92 245
Net successful wells drilled 161 80 201
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Success rate 96% 87% 82%
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- Q1/08 North American natural gas production decreased 11% from
Q1/07 and decreased 3% from Q4/07, reflecting natural declines in
base production and the Company's strategic decision to reduce
spending on natural gas drilling. Despite the decrease in
production, the Company had a highly successful winter drilling
program with all planned wells drilled and all planned tie-ins
completed prior to spring break-up.
- Canadian Natural drilled 167 net targeted natural gas wells in
Q1/08 with an active program across the Company's core regions. In
Northeast British Columbia, 20 net wells were drilled, while in
Northwest Alberta, 50 net wells were drilled. In the Northern
Plains, 44 net wells were drilled, with 53 net wells drilled in the
Southern Plains.
- Planned drilling activity for Q2/08 includes 8 natural gas
wells compared to drilling activity for Q2/07 of 6 natural gas
wells.
North America crude oil and NGLs
Quarterly Results
---------------------------------------
Q1/08 Q4/07 Q1/07
----------------------------------------------------------------------------
Crude oil and NGLs production (bbl/d) 248,960 256,843 237,489
----------------------------------------------------------------------------
Net wells targeting crude oil 176 172 207
Net successful wells drilled 171 168 191
----------------------------------------------------------------------------
Success rate 97% 98% 92%
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- Q1/08 North America crude oil and NGLs production increased 5%
from Q1/07 and decreased 3% from Q4/07 levels. The majority of the
incremental production volume from Q1/07 was contributed by thermal
crude oil and Pelican Lake crude oil. The decrease from Q4/07 is a
reflection of transitioning off the production cycle peaks at
Primrose North pads.
- The Company has decided to accelerate the drilling of
additional Primrose North pads originally scheduled for 2009
requiring additional capital in 2008 of approximately $130 million;
approximately 49 additional horizontal wells of the 120 well
program will be drilled in 2008 with the remainder drilled in 2009.
Steaming of these wells will commence in Q4/09.
- The Primrose East Expansion, a new facility located 15
kilometers from the existing Primrose South steam plant and 25
kilometers from the Wolf Lake central processing facility, is
targeted to add approximately 40,000 bbl/d of crude oil. Drilling
and construction is on schedule, and production is targeted to
commence in early 2009. Primrose East is the second phase of the
300,000 bbl/d conventional expansion plan identified to unlock the
value from Canadian Natural's thermal crude oil resource base.
- In early 2007, Canadian Natural announced its proposed third
phase of the thermal growth plan with a development plan for the
45,000 bbl/d Kirby In-Situ Oil Sands Project located approximately
85 km northeast of Lac La Biche in the Regional Municipality of
Wood Buffalo. The Company has filed its formal regulatory
application documents for this project as part of the Company's
normal course of business.
- Development of new pads and secondary recovery conversion
projects at Pelican Lake continued as expected throughout Q1/08. In
Q1/08, the Company drilled 25 horizontal wells with plans to drill
an additional 57 horizontal and 7 vertical service wells throughout
the remainder of 2008. Pelican Lake production averaged
approximately 37,000 bbl/d for Q1/08 compared to approximately
32,000 bbl/d for Q1/07 and approximately 36,000 bbl/d for the prior
quarter. The response from the polymer flood project continues to
be positive and the Company is moving forward on converting regions
currently under waterflood to polymer flood and expanding the
polymer flood to new areas.
- Conventional heavy crude oil production volumes decreased
slightly in Q1/08 compared to Q4/07, reflecting expected declines
in certain older fields and higher than forecast downtime due to
cold weather.
- During Q1/08, drilling activity targeted 176 net wells
including 96 wells targeting heavy crude oil, 25 wells targeting
Pelican Lake crude oil, 22 wells targeting thermal crude oil and 33
wells targeting light crude oil.
- Planned drilling activity for Q2/08 includes 62 net crude oil
wells, excluding stratigraphic test and service wells.
International
Quarterly Results
----------------------------------------
Q1/08 Q4/07 Q1/07
----------------------------------------------------------------------------
Crude oil production (bbl/d)
North Sea 49,568 52,709 61,869
Offshore West Africa 28,689 27,688 27,643
----------------------------------------------------------------------------
Natural gas production (mmcf/d)
North Sea 11 13 15
Offshore West Africa 14 14 8
----------------------------------------------------------------------------
Net wells targeting crude oil 2.2 0.6 2.8
Net successful wells drilled 2.2 0.6 2.8
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Success rate 100% 100% 100%
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North Sea
- During Q1/08, 1.6 net wells were drilled and completed with an
additional 1.6 net wells drilling at quarter end. Crude oil
production was down 6% in Q1/08 to 49,568 bbl/d from 52,709 bbl/d
in Q4/07 as a result of the disposal of Canadian Natural's
interests in the B-Block Fields in December 2007, higher than
anticipated downtime on Banff and further decline in the Lyell
subsea wells.
- Focus on waterflood optimization at Ninian continued with 1
well being converted to water injection during Q1/08 and a further
well scheduled to be converted to water injection in Q2/08 to
increase water injection capacity. Compared to Q1/07, the Company
has increased injection by 45%.
- At Murchison, the first of 2 production wells planned for 2008
was completed during Q1/08. The second well is scheduled for
completion in Q2/08.
- Following disappointing injection performance from the subsea
wells drilled at Columba E in 2007, the Company has successfully
increased injection by 60% with the optimization of the current
pumps to inject above fracture pressure. As a result, a positive
production response is forecast for later in 2008.
Offshore West Africa
- During Q1/08, 0.6 net crude oil wells were drilled and
completed. This represented the final well in the West Espoir
drilling campaign with the drilling rig being released during the
quarter. The project was delivered on budget and on schedule.
- Offshore West Africa's crude oil production was up 4% in Q1/08
to 28,689 bbl/d from 27,688 bbl/d in Q4/07 following the successful
completion of drilling at West Espoir and stable production from
Baobab.
- Progress on the Facility Upgrade Project at Espoir to increase
capacity of the Floating, Production, Storage and Offtake Vessel
("FPSO") is progressing ahead of schedule and is expected to now be
complete in Q3/09, an acceleration of 3 to 6 months from the
original estimate.
- The deep water drilling rig for Baobab was mobilized early in
Q2/08, enabling work to begin on the restoration of shut-in
production. It is targeted that a minimum 3 of the 5 shut-in Baobab
wells be on stream over the course of 2008 and 2009.
- At the Olowi project in Offshore Gabon, a drilling rig was
mobilized and drilling commenced in early May of this year with
first crude oil production targeted for late 2008.
Horizon Project
- Canadian Natural achieved an overall 94% completion at the end
of Q1/08, with craftspeople actively performing hydrotests,
airblows, rotation checks and various pre-commissioning activities.
Operations teams are walking down the systems in each plant to
ensure they are complete prior to commissioning. The last
substation on site has been energized and the Extraction Plant
started operating on water in late April.
- Mine Production commenced operations in the first quarter,
using Canadian Natural mine operators and equipment to work on the
overburden removal. This is the second area of the Horizon Project
where operations have begun, with water systems being the first.
This represents a significant milestone for the Company with early
operations providing training benefits for Canadian Natural
operators prior to full start up.
- Commissioning is progressing as 96 plant systems have been
turned over and commissioned (out of an estimated 820); along with
10 mine haul trucks (out of 23) and 2 hydraulic shovels, all on
schedule. The balance of the mine equipment will be turned over and
commissioned to support the ramp up of oil sands mining and bitumen
production.
- At the end of the first quarter, capital spending on Phase 1
of the Horizon Project was at 111% of the original budget of $6.8
billion. Looking forward to completion, targeted for Q3/08,
anticipated capital spending on Phase 1 construction will be within
the previously announced range of 25%-28% above the original
budget.
- There has been progress in hiring of operators with 89% of
required personnel in place, all maintenance contracts finalized
and all supervision mobilized on site. The plants are prepared to
start up and 190,000 barrels of diluent for start up have been
delivered to the Horizon Project site.
- Once commissioning has been completed and operations have
begun, it is anticipated that ramp up to full production will occur
over a 3 to 4 month period. The target is to be at 85% design
capacity by year end 2008. Full capacity is anticipated to be
achieved during Q1/09 as planned.
- The sales pipeline which will transport production from the
site to Edmonton is on track for completion in Q2/08. Approximately
750,000 barrels of synthetic crude oil from initial production
volumes will be used to fill the pipeline.
- While focus remains on completion and start up of Phase 1,
Canadian Natural continues to plan for future expansions. Two coke
drums have been received on site along with all components for the
two hydrotreating reactors that will be installed as part of the
Phase 2/3 expansion.
HORIZON PROJECT STATUS SUMMARY
December 31,
2007 March 31, 2008 June 30, 2008
--------------------------------------------------------------
Actual Actual Q1/08 Original Q2/08 Original
Forecast Plan Forecast Plan
--------------------------------------------------------------
Phase 1 - Work
progress
(cumulative) 90% 94% 95% 97% 97% 99%
Phase 1 -
Construction
capital
spending(1)
(cumulative) 99% 111% 110% 97% 122% 100%
(1) Relative to overall Phase 1 project capital of $6.8 billion
Accomplished to the end of the First Quarter of 2008
Procurement
- Site assembly of Mine Operations equipment (shovels and heavy
haul trucks) is on schedule.
- Fixed Plant Maintenance contractors have mobilized.
Modularization
- All oversized loads for construction have been delivered to
site. Ongoing deliveries of mine equipment (trucks and shovels)
will continue through the summer.
Construction
- Overall construction progress is 91% complete.
- Mine overburden removal has moved 56.7 million bank cubic
meters, which represents approximately 80% of the total to be moved
before start up.
- Completed Tar River Diversion and Fish Habitat
construction.
- Substantially completed Extraction Plant in the first quarter
and have introduced water to the plant in April.
- Completed construction of Tanks 11 and 12 in the East Tank
Farm and filled with diluent for start up.
- Installed 3 nitrogen storage tanks and completed construction
of the Nitrogen Plant, now ready for operations.
- Installed Auxiliary Boiler in Cogeneration.
- Assumed occupancy of Main Warehouse.
- Substations energized for Sulphur Recovery and Gas Treating,
representing the last on-site substations to be energized.
- Substantially completed construction of Amine Plant and moving
into Pre-Commissioning.
- Started construction of Sulphur Pipeline.
- Completed piping in Heat Integration.
Systems Commissioned and Turned Over during the Quarter
- Firewater in both tank farms.
- Tanks 11 and 12.
- Electrical Distribution to Heat Integration, Coker/DRU, Tank
Farms and Froth Treatment.
- Substations in Sulphur and Gas Treating energized.
Commissioning Schedule
Completed To Date
- Permanent Potable Water Treatment
- Permanent Sewage Treatment
- Natural Gas Pipeline
- Raw and Recycled Water Pipelines
- River Water Intake and Pumphouse
- Raw Water Pond and Pumphouse
- Recycle Water Pond and Pumphouse
- Electrical Distribution System, including all substations
- Tanks 11 and 12 completed for diluent fill
- Main Piperack (air, water, gas, power)
- Instrument and Utility Air System
On Track for Q2 2008
- Extraction
- Flare System
- Cogeneration (steam)
- Cooling and Heating
- Delayed Coker / Diluent Recovery Unit
- Hydrogen Plant
- Gas Treating and Sulphur Recovery
- West Tank Farm (inter plant)
- Sulphur Block Pipelines
- Synthetic Crude Oil (product) Pipeline
On Track for Q3 2008
- Ore Preparation Plant
- Froth Treatment
- Cogeneration (power)
- Pipeline Corridors
- Hydrotreater
- Remainder of East Tank Farm (product)
MARKETING Quarterly Results
----------------------------------------
Q1/08 Q4/07 Q1/07
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Crude oil and NGLs pricing
WTI(1) benchmark price (US$/bbl) $ 97.96 $ 90.63 $ 58.23
Western Canadian Select blend
differential(2) from WTI (%) 22% 37% 27%
Corporate average pricing before
risk management (C$/bbl) $ 78.99 $ 58.03 $ 51.71
Natural gas pricing
AECO benchmark price (C$/GJ) $ 6.76 $ 5.69 $ 7.07
Corporate average pricing before
risk management (C$/mcf) $ 7.77 $ 6.28 $ 7.74
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(1) Refers to West Texas Intermediate (WTI) crude oil barrel priced at
Cushing, Oklahoma.
(2) Beginning in Q1 2008, the Company has quantified the Heavy Differential
using the Western Canadian Select ("WCS") blend as the heavy crude oil
marker. Prior period amounts have been reclassified.
- In Q1/08, the Western Canadian Select heavy crude oil
differential as a percent of WTI was 22%, compared to 37% in Q4/07.
Heavy crude oil differentials improved in Q1/08 due to the
narrowing of cracking spreads at refineries and a tight supply
demand balance in PADD II. The lower cracking spread resulted in
higher demand for heavy crude oil leading to improved
differentials. Total Western Canadian production was down slightly
in the first quarter which also contributed to improved
differentials.
- The Company continues its efforts with other industry players
in finding new markets and easing the logistical constraints in
getting Western Canadian heavy crude oil to new markets, such as
the US Gulf Coast. Canadian heavy crude oil is very competitive
against other international grades available in the US Gulf Coast.
For Q1/08, the differential for the heavy crude oil marker, Mayan
grade, was US$16.79/bbl or 17%.
- During Q1/08, the Company contributed approximately 153,000
bbl/d of its heavy crude oil streams to the Western Canadian Select
blend as market conditions resulted in this strategy offering the
optimal pricing for bitumen.
- Demand for natural gas increased more than expected for Q1/08
leading to increased natural gas pricing. The quarter saw fewer
imports of liquefied natural gas to North America as a result of
stronger pricing in Europe and Asia, resulting in decreased supply
to the United States and Canada. A cold winter also contributed to
increased demand during the quarter along with renewed consumption
from the industrial sector.
FINANCIAL REVIEW
- Canadian Natural has structured its financial position to
profitably grow its conventional crude oil and natural gas
operations over the next several years and to build the financial
capacity to complete the Horizon Project and other major projects.
A brief summary of the Company's strengths are:
-- A diverse asset base geographically and by product - produced
in excess of 583,000 boe/d in Q1/08, comprised of approximately 44%
natural gas and 56% crude oil - with 95% of production located in
G8 countries with stable and secure economies.
-- Financial stability and liquidity - cash flow from operations
of $1.7 billion for Q1/08, available unused bank lines of $2.6
billion at March 31, 2008 and access to capital debt markets
supported by strong credit ratings.
-- Reduced volatility of commodity prices - a proactive
commodity hedging program to reduce the downside risk of volatility
in commodity prices supporting cash flow for its capital
expenditure program throughout the Horizon Project.
-- A strengthening balance sheet with debt to book
capitalization of 44% and debt to EBITDA of 1.6 times, both within
targeted ranges.
- In January 2008, the Company issued US$1,200 million of
unsecured notes comprised of US$400 million of 5.15% unsecured
notes due February 2013, US$400 million of 5.90% unsecured notes
due February 2018, and US$400 million of 6.75% unsecured notes due
February 2039. Proceeds from the securities issues were used to
repay bankers' acceptances under the Company's bank credit
facilities.
- Commencing January 1, 2009, the Company's commodity hedging
program has been revised by its Board of Directors to allow for the
hedging of up to 50% of the near 12 months budgeted production and
up to 25% of the following 13 to 24 months estimated production.
The purchase of put options will continue to be in addition to the
above parameters. The current program allows for hedging of 75% of
the near 12 months budget and production, up to 50% of the
following 13 to 24 months estimated production, and up to 25% of
the expected production in months 25 to 48. The Company continues
to believe that its risk management program meets its objective of
securing funding for its capital projects.
In 2007 and 2008, the Province of Alberta issued certain details
of its proposed changes to the Alberta crude oil and natural gas
royalty regime, effective January 1, 2009. The Company is currently
awaiting finalization and government approval of the royalty
regulations, however it expects that its 2009 and future Alberta
royalty payments will increase as a result of the proposed royalty
changes and that its level of activity in Alberta in aggregate will
be reduced from what it otherwise would have been in the absence of
such royalty changes.
- Declared a quarterly cash dividend on common shares of C$0.10
per common share, payable July 1, 2008.
OUTLOOK
The Company forecasts 2008 production levels before royalties to
average between 1,429 and 1,513 mmcf/d of natural gas and between
316,000 and 366,000 bbl/d of crude oil and NGLs. Q2/08 production
guidance before royalties is forecast to average between 1,479 and
1,513 mmcf/d of natural gas and between 306,000 and 323,000 bbl/d
of crude oil and NGLs. Detailed guidance on production levels,
capital allocation and operating costs can be found on the
Company's website at
http://www.cnrl.com/investor_info/corporate_guidance/.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements in this document or documents incorporated
herein by reference constitute forward-looking statements or
information (collectively referred to herein as "forward-looking
statements") within the meaning of applicable securities
legislation. Forward-looking statements can be identified by the
words "believe", "anticipate", "expect", "plan", "estimate",
"target", "continue", "could", "intend", "may", "potential",
"predict", "should", "will", "objective", "project", "forecast",
"goal", "guidance", "outlook", "effort", "seeks", "schedule" or
expressions of a similar nature suggesting future outcome or
statements regarding an outlook. Disclosure related to expected
future commodity pricing, production volumes, royalties, operating
costs, capital expenditures and other 2008 guidance provided
throughout this Management's Discussion and Analysis ("MD&A"),
constitutes forward-looking statements. In addition, statements
relating to "reserves" are deemed to be forward-looking statements
as they involve the implied assessment based on certain estimates
and assumptions that the reserves described can be profitably
produced in the future. There are numerous uncertainties inherent
in estimating quantities of proved crude oil and natural gas
reserves and in projecting future rates of production and the
timing of development expenditures. The total amount or timing of
actual future production may vary significantly from reserve and
production estimates.
These statements are not guarantees of future performance and
are subject to certain risks and the reader should not place undue
reliance on these forward-looking statements as there can be no
assurance that the plans, initiatives or expectations upon which
they are based will occur.
The forward-looking statements are based on current
expectations, estimates and projections about Canadian Natural
Resources Limited (the "Company") and the industry in which the
Company operates, which speak only as of the date such statements
were made or as of the date of the report or document in which they
are contained, and are subject to known and unknown risks,
uncertainties and other factors that could cause the actual
results, performance or achievements of the Company to be
materially different from any future results, performance or
achievements expressed or implied by such forward-looking
statements. Such factors include, among others: general economic
and business conditions which will, among other things, impact
demand for and market prices of the Company's products; volatility
of and assumptions regarding crude oil and natural gas prices;
fluctuations in currency and interest rates; assumptions on which
the Company's current guidance is based; economic conditions in the
countries and regions in which the Company conducts business;
political uncertainty, including actions of or against terrorists,
insurgent groups or other conflict including conflict between
states; industry capacity; ability of the Company to implement its
business strategy, including exploration and development
activities; impact of competition; the Company's defense of
lawsuits; availability and cost of seismic, drilling and other
equipment; ability of the Company and its subsidiaries to complete
its capital programs; the Company's and its subsidiaries' ability
to secure adequate transportation for its products; unexpected
difficulties in mining, extracting or upgrading the Company's
bitumen products; potential delays or changes in plans with respect
to exploration or development projects or capital expenditures;
ability of the Company to attract the necessary labour required to
build its thermal and oil sands mining projects; operating hazards
and other difficulties inherent in the exploration for and
production and sale of crude oil and natural gas; availability and
cost of financing; the Company's and its subsidiaries' success of
exploration and development activities and their ability to replace
and expand crude oil and natural gas reserves; timing and success
of integrating the business and operations of acquired companies;
production levels; imprecision of reserve estimates and estimates
of recoverable quantities of crude oil, bitumen, natural gas and
liquids not currently classified as proved; actions by governmental
authorities; government regulations and the expenditures required
to comply with them (especially safety and environmental laws and
regulations and the impact of climate change initiatives on capital
and operating costs); asset retirement obligations; the adequacy of
the Company's provision for taxes; and other circumstances
affecting revenues and expenses.
The Company's operations have been, and at times in the future
may be, affected by political developments and by federal,
provincial and local laws and regulations such as restrictions on
production, changes in taxes, royalties and other amounts payable
to governments or governmental agencies, price or gathering rate
controls and environmental protection regulations. Should one or
more of these risks or uncertainties materialize, or should any of
the Company's assumptions prove incorrect, actual results may vary
in material respects from those projected in the forward-looking
statements. The impact of any one factor on a particular
forward-looking statement is not determinable with certainty as
such factors are interdependent upon other factors, and the
Company's course of action would depend upon its assessment of the
future considering all information then available.
Readers are cautioned that the foregoing list of important
factors is not exhaustive. Unpredictable or unknown factors not
discussed in this report could also have material adverse effects
on forward-looking statements. Although the Company believes that
the expectations conveyed by the forward-looking statements are
reasonable based on information available to it on the date such
forward-looking statements are made, no assurances can be given as
to future results, levels of activity and achievements. All
subsequent forward-looking statements, whether written or oral,
attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by these cautionary
statements. Except as required by law, the Company assumes no
obligation to update forward-looking statements should
circumstances or Management's estimates or opinions change.
Management's Discussion and Analysis
Management's Discussion and Analysis of the financial condition
and results of operations of the Company should be read in
conjunction with the unaudited interim consolidated financial
statements for the three months ended March 31, 2008 and the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2007.
All dollar amounts are referenced in millions of Canadian
dollars, except where noted otherwise. The financial statements
have been prepared in accordance with Canadian generally accepted
accounting principles ("GAAP"). This MD&A includes references
to financial measures commonly used in the crude oil and natural
gas industry, such as adjusted net earnings from operations and
cash flow from operations. These financial measures are not defined
by GAAP and therefore are referred to as non-GAAP measures. The
non-GAAP measures used by the Company may not be comparable to
similar measures presented by other companies. The Company uses
these non-GAAP measures to evaluate its performance. The non-GAAP
measures should not be considered an alternative to or more
meaningful than net earnings, as determined in accordance with
GAAP, as an indication of the Company's performance. The measures
adjusted net earnings from operations and cash flow from operations
are reconciled to net earnings in the "Financial Highlights"
section of this MD&A.
The calculation of barrels of oil equivalent ("boe") is based on
a conversion ratio of six thousand cubic feet ("mcf") of natural
gas to one barrel ("bbl") of crude oil to estimate relative energy
content. This conversion may be misleading, particularly when used
in isolation, since the 6 mcf:1 bbl ratio is based on an energy
equivalency at the burner tip and does not represent the value
equivalency at the wellhead.
Production volumes are presented throughout this MD&A on a
"before royalty" or "gross" basis, and realized prices exclude the
effect of risk management activities and transportation and
blending costs, except where noted otherwise. Production on an
"after royalty" or "net" basis is also presented for information
purposes only.
The following discussion refers primarily to the Company's
financial results for the three months ended March 31, 2008 in
relation to the comparable period in 2007 and the fourth quarter of
2007. The accompanying tables form an integral part of this
MD&A. This MD&A is dated May 8, 2008. Additional
information relating to the Company, including its Annual
Information Form for the year ended December 31, 2007, is available
on SEDAR at www.sedar.com.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Revenue, before royalties $ 3,967 $ 3,200 $ 3,118
Net earnings $ 727 $ 798 $ 269
Per common share -- basic and
diluted $ 1.35 $ 1.48 $ 0.50
Adjusted net earnings from
operations (1) $ 872 $ 546 $ 621
Per common share -- basic and
diluted $ 1.61 $ 1.02 $ 1.15
Cash flow from operations (2) $ 1,725 $ 1,486 $ 1,622
Per common share -- basic and
diluted $ 3.19 $ 2.75 $ 3.01
Capital expenditures, net of
dispositions $ 1,753 $ 1,514 $ 2,009
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Adjusted net earnings from operations is a non-GAAP measure that
represents net earnings adjusted for certain items of a non-operational
nature. The Company evaluates its performance based on adjusted net
earnings from operations. The reconciliation "Adjusted Net Earnings from
Operations" below lists the after-tax effects of certain items of a
non-operational nature that are included in the Company's financial
results. Adjusted net earnings from operations may not be comparable to
similar measures presented by other companies.
(2) Cash flow from operations is a non-GAAP measure that represents net
earnings adjusted for non-cash items before working capital adjustments.
The Company evaluates its performance based on cash flow from
operations. The Company considers cash flow from operations a key
measure as it demonstrates the Company's ability to generate the cash
flow necessary to fund future growth through capital investment and to
repay debt. The reconciliation "Cash Flow from Operations" below lists
certain non-cash items that are included in the Company's financial
results. Cash flow from operations may not be comparable to similar
measures presented by other companies.
Adjusted Net Earnings from Operations
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2008 2007 2007
----------------------------------------------------------------------------
Net earnings as reported $ 727 $ 798 $ 269
Stock-based compensation expense
(recovery), net of tax (a) - (11) 17
Unrealized risk management loss,
net of tax (b) 76 593 362
Unrealized foreign exchange loss
(gain), net of tax (c) 110 (41) (27)
Effect of statutory tax rate and
other legislative changes on
future income tax liabilities (d) (41) (793) -
----------------------------------------------------------------------------
Adjusted net earnings from
operations $ 872 $ 546 $ 621
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) The Company's employee stock option plan provides for a cash payment
option. Accordingly, the intrinsic value of the outstanding vested
options is recorded as a liability on the Company's balance sheet and
periodic changes in the intrinsic value are recognized in net earnings
or are capitalized as part of the Horizon Oil Sands Project during the
construction period.
(b) Derivative financial instruments are recorded at fair value on the
balance sheet, with changes in fair value of non-designated hedges
flowing through net earnings. The amounts ultimately realized may be
materially different than reflected in the financial statements due to
changes in prices of the underlying items hedged, primarily crude oil
and natural gas.
(c) Unrealized foreign exchange gains and losses result primarily from the
translation of US dollar denominated long-term debt to period-end
exchange rates, offset by the impact of cross currency swaps, and are
immediately recognized in net earnings.
(d) All substantively enacted adjustments in applicable income tax rates and
other legislative changes are applied to underlying assets and
liabilities on the Company's consolidated balance sheet in determining
future income tax assets and liabilities. The impact of these tax rate
and other legislative changes is recorded in net earnings during the
period the legislation is substantively enacted. Income tax rate changes
in the first quarter of 2008 resulted in a reduction of future income
tax liabilities of approximately $19 million in North America and $22
million in Cote d'Ivoire, Offshore West Africa. Income tax rate and
other legislative changes in the fourth quarter of 2007 resulted in a
reduction of future income tax liabilities of approximately $793
million in North America.
Cash Flow from Operations
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2008 2007 2007
----------------------------------------------------------------------------
Net earnings $ 727 $ 798 $ 269
Non-cash items:
Depletion, depreciation and
amortization 688 719 709
Asset retirement obligation
accretion 17 17 18
Stock-based compensation expense
(recovery) - (16) 25
Unrealized risk management loss 108 845 536
Unrealized foreign exchange loss
(gain) 126 (47) (32)
Deferred petroleum revenue tax
(recovery) expense (21) 17 (3)
Future income tax expense (recovery) 80 (847) 100
----------------------------------------------------------------------------
Cash flow from operations $ 1,725 $ 1,486 $ 1,622
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
Net earnings for the first quarter of 2008 were $727 million
compared to $269 million for the first quarter of 2007 and $798
million for the prior quarter. Net earnings for the first quarter
of 2008 included net unrealized after-tax expenses of $145 million
related to the effects of risk management activities, fluctuations
in foreign exchange rates, fluctuations in stock-based compensation
expense and the impact of statutory tax rate changes on future
income tax liabilities, compared to net unrealized after-tax
expenses of $352 million for the first quarter of 2007 and net
unrealized after-tax income of $252 million for the prior quarter.
Excluding these items, adjusted net earnings from operations for
the first quarter of 2008 increased to $872 million compared to
$621 million for the first quarter of 2007 and $546 million for the
prior quarter. The increase in adjusted net earnings from the first
quarter of 2007 was primarily due to the impact of higher realized
pricing, lower depletion, depreciation and amortization expense,
lower interest expense, and lower administration expense. These
factors were partially offset by higher realized risk management
losses, higher royalty and production expense, lower sales volumes
and the impact of the stronger Canadian dollar relative to the US
dollar. The increase from the prior quarter was primarily due to
the impact of higher realized pricing, lower depletion,
depreciation and amortization expense, and the impact of the weaker
Canadian dollar relative to the US dollar, partially offset by
higher realized risk management losses, higher royalty and
production expense, and lower sales volumes.
The Company expects that consolidated net earnings will continue
to reflect significant quarterly volatility due to the impact of
risk management activities, stock-based compensation expense and
fluctuations in foreign exchange rates.
The Company's commodity hedging program reduces the risk of
volatility in commodity price markets and supports the Company's
cash flow for its capital expenditures throughout the Horizon Oil
Sands Project ("Horizon Project") construction period. This program
currently allows for the hedging of up to 75% of the near 12 months
budgeted production, up to 50% of the following 13 to 24 months
estimated production and up to 25% of production expected in months
25 to 48. For the purpose of this program, the purchase of put
options is in addition to the above parameters. In accordance with
the policy, approximately 61% of budgeted crude oil volumes are
hedged for the remainder of 2008, approximately 18% of budgeted
natural gas volumes are hedged for the second and third quarters of
2008 and approximately 6% of estimated crude oil volumes are hedged
for 2009. In addition, 50,000 bbl/d of crude oil volumes are
protected by put options for the remainder of 2008 at a strike
price of US$55.00 per barrel and 50,000 bbl/d of crude oil volumes
are protected by put options for 2009 at a strike price of US$80.00
per barrel.
Commencing January 1, 2009, following the planned completion of
Phase 1 of the Horizon Project, the Company's commodity hedging
program has been revised by its Board of Directors to allow for the
hedging of up to 50% of the near 12 months budgeted production and
up to 25% of the following 13 to 24 months estimated production.
The purchase of put options will continue to be in addition to the
above parameters.
The Company's outstanding commodity related financial
derivatives as at March 31, 2008 are detailed in the "Liquidity and
Capital Resources" section of this MD&A.
The commodity derivative financial instruments currently
outstanding have not been designated as hedges for accounting
purposes (the "non-designated hedges"). The fair value of these
non-designated hedges is based on prevailing forward commodity
prices in effect at the end of each reporting period and is
reflected in risk management activities in consolidated net
earnings. The cash settlement amount of the risk management
derivative financial instruments may vary materially depending upon
the underlying crude oil and natural gas prices at the time of
final settlement of the derivative financial instruments, as
compared to their mark-to-market value at March 31, 2008.
Due to changes in crude oil and natural gas forward pricing and
the reversal of prior period unrealized gains and losses, the
Company recorded a net unrealized loss of $108 million ($76 million
after-tax) on its commodity risk management activities for the
three months ended March 31, 2008. Mark-to-market unrealized gains
and losses do not impact the Company's current cash flow or its
ability to finance ongoing capital programs. The Company continues
to believe that its risk management program meets its objective of
securing funding for its capital projects. For further details,
refer to the "Risk Management Activities" section of this
MD&A.
For the first quarter of 2008, no stock-based compensation
expense was recognized as the expense associated with options
vesting in the normal course was offset by the impact of the lower
share price at March 31, 2008 (Company's share price as at: March
31, 2008 - C$70.27; December 31, 2007 - C$72.58; March 30, 2007 -
C$63.75; December 31, 2006 - C$62.15). As required by GAAP, the
Company records a liability for potential cash payments to settle
its outstanding employee stock options each reporting period based
on the difference between the exercise price of the stock options
and the market price of the Company's common shares, pursuant to a
graded vesting schedule. The liability is revalued quarterly to
reflect the changes in the market price of the Company's common
shares and the options exercised or surrendered in the period, with
the net change recognized in net earnings, or capitalized as part
of the Horizon Project during the construction period. The
stock-based compensation liability at March 31, 2008 reflected the
Company's potential cash liability should all the vested options be
surrendered for a cash payout at the market price on March 31,
2008. In periods when substantial share price changes occur, the
Company's net earnings are subject to significant volatility. The
Company utilizes its stock-based compensation plan to attract and
retain employees in a competitive environment. All employees
participate in this plan.
Cash flow from operations for the first quarter of 2008
increased to $1,725 million compared to $1,622 million for the
first quarter of 2007 and $1,486 million for the prior quarter. The
increase from the first quarter of 2007 was primarily due to the
impact of higher realized pricing, partially offset by higher
realized risk management losses, higher royalty and production
expense, higher current income tax expense, lower sales volumes and
the impact of the stronger Canadian dollar relative to the US
dollar. The increase from the prior quarter was primarily due to
the impact of higher realized pricing and the impact of the weaker
Canadian dollar relative to the US dollar, partially offset by
higher realized risk management losses, higher royalty and
production expense and higher current income tax expense.
Total production before royalties for the first quarter of 2008
decreased 5% to 583,488 boe/d from 613,114 boe/d for the first
quarter of 2007 and 3% from 601,908 boe/d for the prior
quarter.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results for the eight
most recently completed quarters:
($ millions, except per common share Mar 31 Dec 31 Sep 30 Jun 30
amounts) 2008 2007 2007 2007
----------------------------------------------------------------------------
Revenue, before royalties $ 3,967 $ 3,200 $ 3,073 $ 3,152
Net earnings $ 727 $ 798 $ 700 $ 841
Net earnings per common share
- Basic and diluted $ 1.35 $ 1.48 $ 1.30 $ 1.56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per common share Mar 31 Dec 31 Sep 30 Jun 30
amounts) 2007 2006 2006 2006
----------------------------------------------------------------------------
Revenue, before royalties $ 3,118 $ 2,826 $ 3,108 $ 3,041
Net earnings $ 269 $ 313 $ 1,116 $ 1,038
Net earnings per common share
- Basic and diluted $ 0.50 $ 0.58 $ 2.08 $ 1.93
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings over the eight most recently completed quarters
generally reflected fluctuations in realized crude oil and natural
gas prices, fluctuations in sales volumes, the impact of
mark-to-market accounting of financial instruments, fluctuations in
depletion, depreciation and amortization charges, fluctuations in
foreign exchange rates, and adjustments to future income tax
liabilities due to statutory tax rate and other legislative
changes. More specifically, volatility in quarterly net earnings
was primarily due to:
- Crude oil pricing
Crude oil prices reflected demand growth, continued geopolitical
uncertainties and fluctuations in the Heavy Crude Oil Differential
from WTI ("Heavy Differential") in North America.
- Natural gas pricing
Natural gas prices primarily reflected seasonal fluctuations in
both the demand for natural gas and inventory storage levels and
fluctuations in liquefied natural gas imports into the US.
- Crude oil and NGLs sales volumes
Crude oil and NGLs sales volumes primarily reflected increased
production from the Company's Primrose thermal projects, the
results from the Pelican Lake water and polymer flood projects,
development of West and East Espoir, and additional sales volumes
from the Anadarko Canada Corporation ("ACC") acquisition completed
in the fourth quarter of 2006. Crude oil and NGLs sales volumes
also reflected fluctuations in production from the North Sea due to
timing of maintenance activities and liftings and the impact of
shut-in Baobab production in Offshore West Africa.
- Natural gas sales volumes
Natural gas sales volumes primarily reflected additional natural
gas volumes as a result of the ACC acquisition and internally
generated growth. The increases were partially offset by production
declines due to the Company's strategic reduction in natural gas
drilling activity.
- Foreign exchange rates
A general strengthening of the Canadian dollar relative to the
US dollar has decreased the realized price the Company received for
its crude oil and natural gas sales, as sales prices are based
predominately on US dollar denominated benchmarks. Similarly,
unrealized foreign exchange gains and losses were recorded with
respect to US dollar denominated debt balances and the
re-measurement of North Sea future income tax liabilities
denominated in UK pounds sterling to US dollars, partially offset
by the impact of cross currency swaps.
- Risk management
Net earnings have fluctuated due to the recognition of realized
and unrealized gains and losses from the mark-to-market of the
Company's risk management activities.
- Changes in income tax expense
Income tax expense (recovery) fluctuations include statutory tax
rate and other legislative changes enacted or substantively enacted
in the various periods.
- Stock-based compensation
Net earnings have fluctuated due to the mark-to-market movements
of the Company's stock-based compensation liability. Stock-based
compensation expense (recovery) reflected fluctuations in the
Company's share price over the eight most recently completed
quarters.
- Production expense
Production expense has fluctuated company wide primarily due to
the impact for the demand for services, the industry-wide
inflationary cost pressures experienced in prior years in all
segments and the impact of seasonal costs that are dependent on
weather and the fluctuations in product mix.
- Depletion, depreciation and amortization
Depletion, depreciation and amortization expense has fluctuated
due to changes in sales volumes, finding and development costs
associated with crude oil and natural gas exploration, estimated
future costs to develop the Company's proved undeveloped reserves,
and a higher depletion base in North America related to the ACC
acquisition.
OPERATING HIGHLIGHTS
Three Months Ended
------------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
Sales price (2) $ 78.99 $ 58.03 $ 51.71
Royalties 8.70 6.66 4.92
Production expense 14.81 11.53 13.81
----------------------------------------------------------------------------
Netback $ 55.48 $ 39.84 $ 32.98
----------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2) $ 7.77 $ 6.28 $ 7.74
Royalties 1.35 0.94 1.48
Production expense 1.03 0.91 0.97
----------------------------------------------------------------------------
Netback $ 5.39 $ 4.43 $ 5.29
----------------------------------------------------------------------------
Barrels of oil equivalent ($/boe) (1)
Sales price (2) $ 65.09 $ 49.23 $ 49.32
Royalties 8.43 6.21 6.76
Production expense 11.02 8.85 10.10
----------------------------------------------------------------------------
Netback $ 45.64 $ 34.17 $ 32.46
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
BUSINESS ENVIRONMENT
Three Months Ended
------------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
WTI benchmark price (US$/bbl) $ 97.96 $ 90.63 $ 58.23
Dated Brent benchmark price
(US$/bbl) $ 96.94 $ 88.65 $ 57.76
WCS blend differential from WTI
(US$/bbl) (1) $ 21.41 $ 33.74 $ 15.48
WCS blend differential from
WTI (%) (1) 22% 37% 27%
Condensate benchmark price (US$/bbl) $ 98.40 $ 90.89 $ 58.78
NYMEX benchmark price (US$/mmbtu) $ 8.07 $ 7.03 $ 6.96
AECO benchmark price (C$/GJ) $ 6.76 $ 5.69 $ 7.07
US / Canadian dollar average
exchange rate $ 0.9958 $ 1.0193 $ 0.8535
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Beginning in Q1 2008, the Company has quantified the Heavy Differential
using the Western Canadian Select ("WCS") blend as the heavy crude oil
marker. Prior period amounts have been reclassified.
Commodity Prices
Crude oil sales contracts in the North America segment are
typically based on WTI benchmark pricing. WTI averaged US$97.96 per
bbl for the first quarter of 2008, an increase of 68% from US$58.23
per bbl for the first quarter of 2007, and an increase of 8% from
US$90.63 for the prior quarter. WTI pricing during the first
quarter of 2008 generally reflected continued strong demand for
crude oil and continued geopolitical events resulting in increased
market uncertainty.
Crude oil sales contracts for the Company's North Sea and
Offshore West Africa segments are typically based on Dated Brent
("Brent") pricing, which generally continued to benefit from strong
European and Asian demand. Brent averaged US$96.94 per bbl for the
first quarter of 2008, an increase of 68% compared to US$57.76 per
bbl for the first quarter of 2007, and an increase of 9% from
US$88.65 per bbl for the prior quarter.
The Company's realized crude oil prices increased from the first
quarter of 2007 and the prior quarter primarily as a result of
increased WTI and Brent pricing and a narrower Heavy Differential,
offset by the impact of a strong Canadian dollar. The Heavy
Differential averaged 22% for the first quarter of 2008 compared to
27% for the first quarter of 2007, and 37% for the prior quarter.
The narrowing of the Heavy Differential from the prior period was
primarily due to reduced Canadian production of heavy crude oil and
reduced refinery cracking margins. Realized prices continued to be
adversely impacted by the strong Canadian dollar.
The Company anticipates continued volatility in the crude oil
pricing benchmarks due to the unpredictable nature of geopolitical
events and potential refinery outages. The Heavy Differential is
expected to continue to reflect seasonal demand fluctuations and
refinery cracking margins.
NYMEX natural gas prices averaged US$8.07 per mmbtu for the
first quarter of 2008, an increase of 16% from US$6.96 per mmbtu
for the first quarter of 2007, and an increase of 15% from US$7.03
per mmbtu for the prior quarter. AECO natural gas prices for the
first quarter of 2008 decreased 4% from $7.07 per GJ in the first
quarter of 2007 to average $6.76 per GJ, and increased 19% from
$5.69 per GJ for the prior quarter. Fluctuations in natural gas
prices from the comparable periods were primarily related to higher
overall demand and lower storage levels, resulting from the colder
weather experienced late in the first quarter of 2008, and lower
liquefied natural gas imports into the US during the first quarter
of 2008.
Operating, Royalty and Capital Costs
Strong commodity prices in recent years have resulted in
increased demand and costs for oilfield services worldwide. This
has lead to inflationary operating and capital cost pressures
throughout the North America crude oil and natural gas industry,
particularly related to drilling activities and oil sands
developments. The strong commodity price environment has also
impacted costs in international basins, due in large part to the
high demand for offshore drilling rigs.
The crude oil and natural gas industry is also experiencing cost
pressures related to environmental regulations, both in North
America and internationally. In Canada, the Federal Government has
indicated its intent to develop regulations that would be in effect
in 2010 to address industrial greenhouse gas ("GHG") emissions. The
Federal Government has also outlined national and sectoral
reduction targets for several categories of air pollutants. In
Alberta, GHG regulations came into effect July 1, 2007, affecting
facilities emitting more than 100 kilotonnes of CO2e annually. Two
of the Company's facilities, the Primrose/Wolf Lake in-situ heavy
crude oil facilities and the Hays sour gas plant, are captured
under the regulations. In the UK, GHG regulations have been in
effect since 2005. During Phase 1 (2005-2007) of the UK National
Allocation Plan the Company operated below its CO2 allocation. For
Phase 2 (2008-2012) the Company's CO2 allocation has been decreased
below the Company's estimated current operations emissions. The
Company continues to focus on implementing reduction programs based
on efficiency audits to reduce CO2 emissions at its major
facilities and on trading mechanisms to ensure compliance with any
requirement now in effect.
During the first quarter of 2008, British Columbia announced a
carbon tax on fuel consumed in the province. Commencing July 1,
2008, the carbon tax will be assessed at $10/tonne of CO2e,
increasing to $30/tonne by July 1, 2012.
Continued cost pressures and the final outcome of changes to
environmental regulations may adversely impact the Company's future
net earnings, cash flow and capital projects.
In 2007 and 2008, the Province of Alberta issued certain details
of its proposed changes to the Alberta crude oil and natural gas
royalty regime, effective January 1, 2009. These proposed changes
include:
- The implementation of a sliding scale for oil sands royalties
ranging from 1% to 9% on a gross revenue basis pre-payout and 25%
to 40% on a net revenue basis post-payout depending on benchmark
crude oil pricing; and
- New royalty formulas for conventional crude oil and natural
gas that are to operate on sliding scales ranging up to 50%
determined by commodity prices and well productivity.
The Company is currently awaiting finalization and government
approval of the royalty regulations, however it expects that its
2009 and future Alberta royalty payments will increase as a result
of the proposed royalty changes and that its level of activity in
Alberta in aggregate will be reduced from what it otherwise would
have been in the absence of such royalty changes.
PRODUCT PRICES
Three Months Ended
------------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1) (2)
North America $ 72.86 $ 50.49 $ 46.09
North Sea $ 99.01 $ 83.44 $ 68.83
Offshore West Africa $ 96.31 $ 81.89 $ 58.60
Company average $ 78.99 $ 58.03 $ 51.71
Natural gas ($/mcf) (1) (2)
North America $ 7.80 $ 6.31 $ 7.79
North Sea $ 3.30 $ 3.62 $ 4.49
Offshore West Africa $ 7.89 $ 5.49 $ 5.97
Company average $ 7.77 $ 6.28 $ 7.74
Company average ($/boe) (1) (2) $ 65.09 $ 49.23 $ 49.32
Percentage of gross revenue (2)
(excluding midstream revenue)
Crude oil and NGLs 68% 66% 56%
Natural gas 32% 34% 44%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
The Company's realized crude oil prices increased 53% to average
$78.99 per bbl for the first quarter of 2008 from $51.71 per bbl
for the first quarter of 2007, and increased 36% from $58.03 per
bbl for the prior quarter. The Company's realized crude oil prices
increased from the first quarter of 2007 and the prior quarter
primarily as a result of an increased WTI and Brent benchmark
prices and a narrower Heavy Differential, partially offset by a
strong Canadian dollar relative to the US dollar.
The Company's realized natural gas price increased marginally to
average $7.77 per mcf for the first quarter of 2008 from $7.74 per
mcf for the first quarter of 2007, and increased 24% from $6.28 per
mcf for the prior quarter. The increase in realized natural gas
prices from the prior quarter primarily reflected colder winter
temperatures during the later part of the first quarter of 2008 and
the impact of an overall reduction by the industry for natural gas
drilling in response to industry wide inflationary pressures. The
reduced drilling activity and production volumes and lower
liquefied natural gas imports contributed to a decrease in natural
gas inventories closer to historical levels.
North America
North America realized crude oil prices increased 58% to average
$72.86 per bbl for the first quarter of 2008 from $46.09 per bbl
for the first quarter of 2007, and increased 44% from $50.49 per
bbl for the prior quarter. The increase from the comparable periods
was due to the increase in WTI benchmark pricing and a narrower
Heavy Differential, partially offset by the impact of the strong
Canadian dollar.
In North America, the Company continues to focus on its crude
oil marketing strategy, including the development of a blending
strategy that expands markets within current pipeline
infrastructure, supporting pipeline projects that will provide
capacity to transport crude oil to new markets, and working with
refiners to add incremental heavy crude oil conversion capacity.
During the first quarter, the Company contributed approximately
153,000 bbl/d of heavy crude oil blends to the WCS stream.
North America realized natural gas prices increased marginally
to average $7.80 per mcf for the first quarter of 2008 from $7.79
per mcf for the first quarter of 2007, and increased 24% from $6.31
per mcf for the prior quarter. Fluctuations in natural gas prices
from the comparable periods in 2007 were primarily related to the
impact of weather and storage levels.
Comparisons of the prices received for the Company's North America
production by product type were as follows:
----------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Wellhead Price (1) (2)
Light/medium crude oil and NGLs
(C$/bbl) $ 88.78 $ 74.96 $ 59.48
Pelican Lake crude oil (C$/bbl) $ 72.77 $ 47.01 $ 44.44
Primary heavy crude oil (C$/bbl) $ 68.61 $ 43.30 $ 41.83
Thermal heavy crude oil (C$/bbl) $ 65.97 $ 42.76 $ 40.31
Natural gas (C$/mcf) $ 7.80 $ 6.31 $ 7.79
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North Sea
North Sea realized crude oil prices increased 44% to average
$99.01 per bbl for the first quarter of 2008 from $68.83 per bbl
for the first quarter of 2007, and by 19% from $83.44 per bbl for
the prior quarter. As revenue in the North Sea is currently
recognized on a liftings basis, realized crude oil prices per
barrel in any particular quarter are dependant on the frequency and
timing of liftings of each field. Realized crude oil prices in the
North Sea during the first quarter continued to benefit from the
impact of strong European and Asian demand, partially offset by the
impact of the strong
Canadian dollar.
Offshore West Africa
Offshore West Africa realized crude oil prices increased 64% to
average $96.31 per bbl for the first quarter of 2008 from $58.60
per bbl for the first quarter of 2007, and increased 18% from
$81.89 per bbl for the prior quarter. As revenue in Offshore West
Africa is recognized on a liftings basis, realized crude oil prices
per barrel in any particular quarter are dependant on the frequency
and timing of liftings of each field, as well as the terms of the
related sales contracts. Realized crude oil prices in Offshore West
Africa during the first quarter continued to benefit from the
impact of strong European and Asian demand, offset by the impact of
the strong Canadian dollar.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when
title transfers to the customer and delivery has taken place. The
related crude oil volumes by segment, which have not been
recognized in revenue,
were as follows:
----------------------------------------
Mar 31 Dec 31 Mar 31
(bbl) 2008 2007 2007
----------------------------------------------------------------------------
North America, related to pipeline
fill 1,097,526 1,097,526 1,097,526
North Sea, related to timing of
liftings 637,755 1,032,723 401,296
Offshore West Africa, related to
timing of liftings 260,649 8,578 230,623
----------------------------------------------------------------------------
1,995,930 2,138,827 1,729,445
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the first quarter of 2008, an additional 143,000 barrels of
crude oil produced in the Company's international operations, which
were deferred and included in inventory at December 31, 2007, were
sold. Notwithstanding the overall reduction, consolidated cash flow
from operations decreased by approximately $6 million in the first
quarter of 2008 as the increase in cash flow derived from
additional sales volumes in the North Sea was more than offset by
the decrease in cash flow due to lower sales volumes in Offshore
West Africa where netbacks are higher.
DAILY PRODUCTION, before royalties
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America 248,960 256,843 237,489
North Sea 49,568 52,709 61,869
Offshore West Africa 28,689 27,688 27,643
----------------------------------------------------------------------------
327,217 337,240 327,001
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,513 1,562 1,694
North Sea 11 13 15
Offshore West Africa 14 14 8
----------------------------------------------------------------------------
1,538 1,589 1,717
----------------------------------------------------------------------------
Total barrels of oil equivalent
(boe/d) 583,488 601,908 613,114
----------------------------------------------------------------------------
Product mix
Light/medium crude oil and NGLs 23% 23% 24%
Pelican Lake crude oil 6% 6% 5%
Primary heavy crude oil 15% 15% 15%
Thermal heavy crude oil 12% 12% 9%
Natural gas 44% 44% 47%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
DAILY PRODUCTION, net of royalties
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America 216,585 217,886 204,401
North Sea 49,473 52,586 61,754
Offshore West Africa 23,496 25,123 25,897
----------------------------------------------------------------------------
289,554 295,595 292,052
----------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,260 1,327 1,367
North Sea 11 13 15
Offshore West Africa 11 12 8
----------------------------------------------------------------------------
1,282 1,352 1,390
----------------------------------------------------------------------------
Total barrels of oil equivalent
(boe/d) 503,250 520,887 523,730
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Daily production and per barrel statistics are presented
throughout this MD&A on a "before royalty" or "gross" basis.
Production on an "after royalty" or "net" basis is also
presented.
The Company's business approach is to maintain large project
inventories and production diversification among each of the
commodities it produces; namely natural gas, light/medium crude oil
and NGLs, Pelican Lake crude oil, primary heavy crude oil and
thermal heavy crude oil.
Total production averaged 583,488 boe/d for the first quarter of
2008, a 5% decrease from 613,114 boe/d for the first quarter of
2007, and a 3% decrease from 601,908 boe/d for the prior
quarter.
Total crude oil and NGLs production for the first quarter of
2008 of 327,217 bbl/d was comparable to 327,001 bbl/d for the first
quarter of 2007, and decreased 3% from 337,240 bbl/d for the prior
quarter. The decrease from the prior quarter was primarily due to
lower production in North America and the North Sea. Crude oil and
NGLs production in the first quarter of 2008 was within the
Company's previously issued guidance of 315,000 to 331,000
bbl/d.
Natural gas production continued to represent the Company's
largest product offering, accounting for 44% of the Company's total
production. Natural gas production for the first quarter of 2008
averaged 1,538 mmcf/d compared to 1,717 mmcf/d for the first
quarter of 2007 and 1,589 mmcf/d for the prior quarter. The
decrease in natural gas production from the comparable periods
primarily reflected production declines due to the Company's
strategic reduction in natural gas drilling activity. First quarter
natural gas production was within the Company's previously issued
guidance of 1,522 to 1,557 mmcf/d.
For 2008, annual production guidance is targeted to average
between 316,000 and 366,000 bbl/d of crude oil and NGLs and between
1,429 and 1,513 mmcf/d of natural gas. Second quarter 2008
production guidance is targeted to average between 306,000 and
323,000 bbl/d of crude oil and NGLs and between 1,479 and 1,513
mmcf/d of natural gas.
North America
North America crude oil and NGLs production for the first
quarter of 2008 increased 5% to average 248,960 bbl/d from 237,489
bbl/d for the first quarter of 2007, and decreased 3% from 256,843
bbl/d for the prior quarter. The fluctuations in crude oil and NGLs
production from the prior periods was primarily due to the cyclic
nature of the Company's thermal production.
For the first quarter of 2008, natural gas production decreased
11% to 1,513 mmcf/d from 1,694 mmcf/d for the first quarter of
2007, and decreased 3% from 1,562 mmcf/d for the prior quarter. The
decrease in natural gas production from the prior periods reflected
production declines due to the Company's strategic decision to
reduce natural gas drilling activity.
North Sea
North Sea crude oil production for the first quarter of 2008
decreased 20% to 49,568 bbl/d from 61,869 bbl/d for the first
quarter of 2007 and by 6% from 52,709 bbl/d for the prior quarter.
Production decreased from the prior quarter due to the sale of the
Company's interests in the B-Block Fields in December 2007, higher
than anticipated downtime on the Banff Field and further decline of
the 2007 Lyell subsea wells.
Offshore West Africa
Offshore West Africa crude oil production increased 4% to 28,689
bbl/d for the first quarter of 2008 from 27,643 bbl/d for the first
quarter of 2007, and by 4% from 27,688 bbl/d for the prior quarter.
Production increased compared with the comparable periods in 2007
due to the progress on the West Espoir drilling program, which was
successfully completed in January 2008, coupled with stable
production from the Baobab Field. In Baobab, the Company has
secured a deepwater rig, on location in April 2008, which should
enable the Company to execute its plan to restore certain of its
shut-in production over the course of 2008 and 2009.
ROYALTIES
Three Months Ended
----------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
North America $ 9.63 $ 7.66 $ 6.42
North Sea $ 0.19 $ 0.19 $ 0.13
Offshore West Africa $ 17.43 $ 7.59 $ 3.70
Company average $ 8.70 $ 6.66 $ 4.92
Natural gas ($/mcf) (1)
North America $ 1.36 $ 0.95 $ 1.50
Offshore West Africa $ 1.43 $ 0.52 $ 0.38
Company average $ 1.35 $ 0.94 $ 1.48
Company average ($/boe) (1) $ 8.43 $ 6.21 $ 6.76
Percentage of revenue (2)
Crude oil and NGLs 11% 11% 10%
Natural gas 17% 15% 19%
Boe 13% 13% 14%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North America
North America crude oil and NGLs royalties per bbl for the first
quarter of 2008 continue to reflect strong realized crude oil
prices. Crude oil and NGLs royalties averaged approximately 13% of
revenues for the first quarter of 2008, compared to 14% for the
first quarter in 2007 and 15% in the prior quarter. Crude oil and
NGLs royalties per bbl are anticipated to average 14% to 16% of
gross revenue for 2008.
Natural gas royalties per mcf generally fluctuate with natural
gas prices. Natural gas royalties averaged approximately 17% of
revenues for the first quarter of 2008 compared to 19% for the
first quarter of 2007 and 15% for the prior quarter. Natural gas
royalties are anticipated to average 17% to 20% of gross revenue
for 2008.
North Sea
North Sea government royalties on crude oil were eliminated
effective January 1, 2003. The remaining royalty is a gross
overriding royalty on the Ninian Field.
Offshore West Africa
Offshore West Africa production is governed by the terms of the
various Production Sharing Contracts ("PSCs"). Under the PSCs,
revenues are divided into cost recovery oil and profit oil. Cost
recovery oil allows the Company to recover its capital and
production costs and the costs carried by the Company on behalf of
the Government State Oil Company. Profit oil is allocated to the
joint venture partners in accordance with their respective equity
interests, after a portion has been allocated to the Government.
The Government's share of profit oil attributable to the Company's
equity interest is allocated between royalty expense and current
income tax expense in accordance with the PSCs. The Company's
capital investments in the Espoir Fields were fully recovered in
the first quarter of 2007, increasing royalty rates and current
income taxes in accordance with the terms of the PSCs.
Royalty rates as a percentage of revenue averaged approximately
18% for the first quarter of 2008 compared to 6% for the first
quarter of 2007 and 9% for the prior quarter. Royalty expense in
the first quarter reflected the relatively high proportion of
Espoir sales in the period and the increase in allocation of the
Government's share to royalties due to the reduction in the Cote
d'Ivoire corporate income tax rate enacted in the first quarter of
2008. Offshore West Africa royalty rates are anticipated to average
12% to 17% of gross revenue for 2008.
PRODUCTION EXPENSE
Three Months Ended
---------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
North America $ 13.88 $ 10.54 $ 13.00
North Sea $ 22.35 $ 18.95 $ 18.57
Offshore West Africa $ 8.03 $ 9.32 $ 8.93
Company average $ 14.81 $ 11.53 $ 13.81
Natural gas ($/mcf) (1)
North America $ 1.01 $ 0.90 $ 0.95
North Sea $ 2.33 $ 1.50 $ 2.58
Offshore West Africa $ 1.25 $ 1.89 $ 1.48
Company average $ 1.03 $ 0.91 $ 0.97
Company average ($/boe) (1) $ 11.02 $ 8.85 $ 10.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
North America
North America crude oil and NGLs production expense for the
first quarter of 2008 increased 7% to $13.88 per bbl from $13.00
per bbl for the first quarter of 2007 and increased 32% from $10.54
per bbl for the prior quarter. The increase in production expense
per barrel for the first quarter of 2008 was a result of the timing
of steam cycles, higher cost of natural gas for fuel for the
Company's thermal operations, and increased seasonal costs related
to winter access areas.
North America natural gas production expense for the first
quarter of 2008 increased 6% to $1.01 per mcf from $0.95 per mcf
for the first quarter of 2007 and increased 12% from $0.90 per mcf
for the prior quarter. The increase in production expense per mcf
was a result of lower sales volumes on the fixed cost portion of
production costs and increased seasonal costs related to winter
access areas.
North Sea
North Sea crude oil production expense increased on a per barrel
basis from the comparable quarters in 2007 due to lower production
volumes on a relatively fixed cost base and the timing of liftings
from various fields.
Offshore West Africa
Offshore West Africa crude oil production expense decreased on a
per barrel basis from the comparable quarters in 2007 primarily due
to the impact of the timing of liftings at the Baobab and Espoir
Fields, resulting in a greater proportion of relatively lower fixed
cost Espoir sales in the quarter.
MIDSTREAM
Three Months Ended
---------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2008 2007 2007
----------------------------------------------------------------------------
Revenue $ 20 $ 19 $ 19
Production expense 5 6 6
----------------------------------------------------------------------------
Midstream cash flow 15 13 13
Depreciation 2 2 2
----------------------------------------------------------------------------
Segment earnings before taxes $ 13 $ 11 $ 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's midstream assets consist of three crude oil
pipeline systems and a 50% working interest in an 84-megawatt
cogeneration plant at Primrose. Approximately 80% of the Company's
heavy crude oil production is transported to international mainline
liquid pipelines via the 100% owned and operated ECHO Pipeline, the
62% owned and operated Pelican Lake Pipeline and the 15% owned Cold
Lake Pipeline. The midstream pipeline assets allow the Company to
control the transport of its own production volumes as well as earn
third party revenue. This transportation control enhances the
Company's ability to manage the full range of costs associated with
the development and marketing of its heavier crude oil.
DEPLETION, DEPRECIATION AND AMORTIZATION (1)
Three Months Ended
---------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Expense ($ millions) $ 686 $ 717 $ 707
$/boe (2) $ 12.87 $ 12.99 $ 12.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) DD&A excludes depreciation on midstream assets.
(2) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, Depreciation and Amortization ("DD&A") for the
first quarter of 2008 decreased in total from the prior quarter and
the first quarter of 2007. The decrease in DD&A expense from
the prior periods was primarily due to the impact of lower sales
volumes.
ASSET RETIREMENT OBLIGATION ACCRETION
Three Months Ended
---------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Expense ($ millions) $ 17 $ 17 $ 18
$/boe (1) $ 0.31 $ 0.31 $ 0.32
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Asset retirement obligation accretion expense represents the
increase in the carrying amount of the asset retirement obligation
due to the passage of time. Accretion expense for the first quarter
of 2008 was consistent with the comparable periods.
ADMINISTRATION EXPENSE
Three Months Ended
---------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Expense ($ millions) $ 43 $ 42 $ 60
$/boe (1) $ 0.80 $ 0.76 $ 1.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for the first quarter of 2008 decreased
in total and on a boe basis from the first quarter of 2007
primarily due to decreased staffing costs, including costs related
to the Company's share bonus program.
STOCK-BASED COMPENSATION EXPENSE (RECOVERY)
Three Months Ended
---------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2008 2007 2007
----------------------------------------------------------------------------
Expense (recovery) $ - $ (16) $ 25
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's Stock Option Plan (the "Option Plan") provides
current employees (the "option holders") with the right to elect to
receive common shares or a direct cash payment in exchange for
options surrendered. The design of the Option Plan balances the
need for a long-term compensation program to retain employees with
the benefits of reducing the impact of dilution on current
Shareholders and the reporting of the obligations associated with
stock options. Transparency of the cost of the Option Plan is
increased since changes in the intrinsic value of outstanding stock
options are recognized each period. The cash payment feature
provides option holders with substantially the same benefits and
allows them to realize the value of their options through a
simplified administration process.
For the first quarter of 2008, no stock-based compensation
expense was recognized as the expense associated with options
vesting in the normal course was offset by the impact of the lower
share price at March 31, 2008 (Company's share price as at: March
31, 2008 - C$70.27; December 31, 2007 - C$72.58; March 31, 2007 -
C$63.75; December 31, 2006 - C$62.15). As required by GAAP, the
Company's outstanding stock options are valued each reporting
period based on the difference between the exercise price of the
stock options and the market price of the Company's common shares,
pursuant to a graded vesting schedule. The liability is revalued
quarterly to reflect changes in the market price of the Company's
common shares and the options exercised or surrendered in the
period, with the net change recognized in net earnings, or
capitalized during the construction period in the case of the
Horizon Project. For the three months ended March 31, 2008, the
Company recorded a $5 million recovery on previously capitalized
stock-based compensation on the Horizon Project (March 31, 2007 -
$9 million capitalized). The stock-based compensation liability
reflected the Company's potential cash liability should all the
vested options be surrendered for a cash payout at the market price
on March 31, 2008. In periods when substantial stock price changes
occur, the Company is subject to significant earnings
volatility.
For the three months ended March 31, 2008, the Company paid $80
million for stock options surrendered for cash settlement (March
31, 2007 - $136 million).
INTEREST EXPENSE
Three Months Ended
---------------------------------------
Mar 31 Dec 31 Mar 31
($ millions, except per boe amounts) 2008 2007 2007
----------------------------------------------------------------------------
Expense, gross $ 160 $ 160 $ 154
Less: capitalized interest, Horizon
Project 111 109 71
----------------------------------------------------------------------------
Expense, net $ 49 $ 51 $ 83
$/boe (1) $ 0.92 $ 0.92 $ 1.49
Average effective interest rate 5.5% 5.5% 5.4%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest expense and the Company's average effective
interest rate increased from the first quarter in 2007 primarily
due to an increased proportion of higher cost US dollar denominated
debt, offset by decreased short term borrowing rates in the first
quarter of 2008 and the impact of the strong Canadian dollar.
On commencement of operations of Phase 1 of the Horizon Project,
interest capitalization will cease on this Phase, increasing
interest expense accordingly.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to
manage its commodity price, currency and interest rate exposures.
These derivative financial instruments are not intended for trading
or speculative purposes.
Three Months Ended
---------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2008 2007 2007
----------------------------------------------------------------------------
Crude oil and NGLs financial
instruments $ 463 $ 308 $ (5)
Natural gas financial instruments (47) (127) (83)
----------------------------------------------------------------------------
Realized loss (gain) $ 416 $ 181 $ (88)
----------------------------------------------------------------------------
Crude oil and NGLs financial
instruments $ 51 $ 770 $ 330
Natural gas financial instruments 59 75 206
Foreign currency swaps (2) - -
----------------------------------------------------------------------------
Unrealized loss $ 108 $ 845 $ 536
----------------------------------------------------------------------------
Net loss $ 524 $ 1,026 $ 448
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The net realized loss (gain) from crude oil and natural gas
financial instruments would have decreased (increased) the
Company's average realized prices as follows:
Three Months Ended
---------------------------------------
Mar 31 Dec 31 Mar 31
2008 2007 2007
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1) $ 15.47 $ 9.99 $ (0.17)
Natural gas ($/mcf) (1) $ (0.33) $ (0.87) $ (0.54)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Complete details related to outstanding derivative financial
instruments at March 31, 2008 are disclosed in note 10 to the
Company's unaudited interim consolidated financial statements.
The commodity derivative financial instruments currently
outstanding have not been designated as hedges for accounting
purposes (the "non-designated hedges"). The fair value of these
non-designated hedges is based on prevailing forward commodity
prices in effect at the end of each reporting period and is
reflected in risk management activities in consolidated net
earnings. The cash settlement amount of the risk management
derivative financial instruments may vary materially depending upon
the underlying crude oil and natural gas prices at the time of
final settlement of the derivative financial instruments, as
compared to their mark-to-market value at March 31, 2008. Due to
changes in crude oil and natural gas forward pricing and the
reversal of prior period unrealized gains and losses, the Company
recorded a net unrealized loss of $108 million ($76 million
after-tax) on its commodity risk management activities for the
three months ended March 31, 2008 (December 31, 2007 - unrealized
loss of $845 million, $593 million after-tax; March 31, 2007 -
unrealized loss of $536 million, $362 million after-tax).
FOREIGN EXCHANGE
Three Months Ended
---------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2008 2007 2007
----------------------------------------------------------------------------
Net realized (gain) loss $ (12) $ - $ 5
Net unrealized loss (gain) (1) 126 (47) (32)
----------------------------------------------------------------------------
Net loss (gain) $ 114 $ (47) $ (27)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency swaps
as described in Risk Management Activities.
The Company's operating results are affected by fluctuations in
the exchange rates between the Canadian dollar, US dollar, and UK
pound sterling. A majority of the Company's revenue is based on
reference to US dollar benchmark prices. An increase in the value
of the Canadian dollar in relation to the US dollar results in
decreased revenue from the sale of the Company's production.
Conversely, a decrease in the value of the Canadian dollar in
relation to the US dollar results in increased revenue from the
sale of the Company's production. Production expenses in the North
Sea are subject to foreign currency fluctuations due to changes in
the exchange rate of the UK pound sterling to the US dollar, while
production expenses in Offshore West Africa are subject to foreign
currency fluctuations due to changes in the exchange rate of the
Canadian dollar to the US dollar. The value of the Company's US
dollar denominated debt is also impacted by the value of the
Canadian dollar in relation to the US dollar.
The net unrealized foreign exchange loss for the first quarter
of 2008 was primarily related to the weakening of the Canadian
dollar in relation to the US dollar with respect to the US dollar
debt, together with the impact of the re-measurement of North Sea
future income tax liabilities denominated in UK pounds sterling to
US dollars. Included in the net unrealized loss for the three
months ended March 31, 2008 was an unrealized gain of $75 million
(three months ended March 31, 2007 - unrealized loss of $37
million) related to the impact of the cross currency swaps. The net
realized foreign exchange gain for the three months ended March 31,
2008 was primarily due to the result of foreign exchange rate
fluctuations on settlement of working capital items denominated in
US dollars or UK pounds sterling. The Canadian dollar ended the
first quarter at US$0.9729 compared to US$1.0120 at December 31,
2007 (March 31, 2007 - US$0.8674).
TAXES
Three Months Ended
---------------------------------------
($ millions, except income tax Mar 31 Dec 31 Mar 31
rates) 2008 2007 2007
----------------------------------------------------------------------------
Current $ 70 $ 16 $ 66
Deferred (21) 17 (3)
----------------------------------------------------------------------------
Taxes other than income tax $ 49 $ 33 $ 63
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America $ 21 $ 31 $ 25
North Sea 96 65 35
Offshore West Africa 38 27 10
----------------------------------------------------------------------------
Current income tax 155 123 70
Future income tax expense (recovery) 80 (847) 100
----------------------------------------------------------------------------
235 (724) 170
Income tax rate and other
legislative changes (1) (2) 41 793 -
----------------------------------------------------------------------------
$ 276 $ 69 $ 170
----------------------------------------------------------------------------
Effective income tax rate before
non-recurring benefits 28.7% 93.2% 38.7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the effect of a one time recovery of $19 million due to British
Columbia corporate income tax rate reductions and $22 million due to
Cote d'Ivoire corporate income tax rate reductions enacted or
substantively enacted during the first quarter of 2008.
(2) Includes the effect of a one time recovery of $793 million due to
Canadian Federal income tax rate reductions and other legislative
changes enacted or substantively enacted during the fourth quarter of
2007.
Taxes other than income tax primarily includes current and
deferred petroleum revenue tax ("PRT"). PRT is charged on certain
fields in the North Sea at the rate of 50% of net operating income,
after allowing for certain deductions including abandonment
expenditures.
Taxable income from the conventional crude oil and natural gas
business in Canada is primarily generated through partnerships,
with the related income taxes payable in a future period. North
America current income taxes have been provided on the basis of the
corporate structure and available income tax deductions and will
vary depending upon the nature, timing and amount of capital
expenditures incurred in Canada in any particular year. In
particular, current taxes in a specific year are sensitive to the
timing of when the Horizon Project capital expenditures are
deductible for Canadian income tax purposes.
CAPITAL EXPENDITURES (1)
Three Months Ended
--------------------------------------
Mar 31 Dec 31 Mar 31
($ millions) 2008 2007 2007
----------------------------------------------------------------------------
Expenditures on property, plant and
equipment
Net property (dispositions)
acquisitions $ (8) $ (107) $ 46
Land acquisition and retention 12 15 29
Seismic evaluations 27 17 50
Well drilling, completion and
equipping 452 341 714
Production and related facilities 319 390 334
----------------------------------------------------------------------------
Total net reserve replacement
expenditures 802 656 1,173
----------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs 665 691 674
Phase 1 operating and capital
inventory 41 - -
Phase 1 commissioning costs 49 - -
Phases 2/3 costs 77 33 44
Capitalized interest, stock-based
compensation and other 109 108 91
----------------------------------------------------------------------------
Total Horizon Project 941 832 809
----------------------------------------------------------------------------
Midstream 1 2 2
Abandonments (2) 6 16 20
Head office 3 8 5
----------------------------------------------------------------------------
Total net capital expenditures $ 1,753 $ 1,514 $ 2,009
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 663 $ 570 $ 998
North Sea 45 44 138
Offshore West Africa 94 43 36
Other - (1) 1
Horizon Project 941 832 809
Midstream 1 2 2
Abandonments (2) 6 16 20
Head office 3 8 5
----------------------------------------------------------------------------
Total $ 1,753 $ 1,514 $ 2,009
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The net capital expenditures exclude adjustments related to differences
between carrying value and tax value.
(2) Abandonments represent expenditures to settle asset retirement
obligations and have been reflected as capital expenditures in this
table.
The Company's strategy is focused on building a diversified
asset base that is balanced among various products. In order to
facilitate efficient operations, the Company concentrates its
activities in core regions where it can dominate the land base and
infrastructure. The Company focuses on maintaining its land
inventories to enable the continuous exploitation of play types and
geological trends, greatly reducing overall exploration risk. By
dominating infrastructure, the Company is able to maximize
utilization of its production facilities, thereby increasing
control over production costs.
Net capital expenditures for the three months ended March 31,
2008 were $1,753 million compared to $2,009 million for the three
months ended March 31, 2007. Capital expenditures in the first
quarter of 2008 primarily reflected the continued progress on the
Company's larger, future growth projects, most notably the Horizon
Project, offset by the effects of an overall strategic reduction in
the North America natural gas drilling program.
For the three months ended March 31, 2008, the Company drilled a
total of 360 net wells consisting of 161 natural gas wells, 173
crude oil wells, 15 stratigraphic test and service wells and 11
wells that were dry. This compared to 688 net wells drilled for the
three months ended March 31, 2007 and 271 net wells drilled in the
prior quarter. The Company achieved an overall success rate of 97%
for the three months ended March 31, 2008, excluding stratigraphic
test and service wells, compared to 87% for the first quarter of
2007 and 94% for the prior quarter.
North America
North America, including the Horizon Project, accounted for
approximately 92% of the total capital expenditures for the three
months ended March 31, 2008 compared to approximately 91% for the
first quarter of 2007 and 94% for the prior quarter.
During the first quarter of 2008, the Company targeted 167 net
natural gas wells, including 20 wells in Northeast British
Columbia, 44 wells in the Northern Plains region, 50 wells in
Northwest Alberta, and 53 wells in the Southern Plains region. The
Company also targeted 176 net crude oil wells during the same
period. The majority of these wells were concentrated in the
Company's crude oil Northern Plains region where 96 heavy crude oil
wells, 25 Pelican Lake crude oil wells, 22 thermal crude oil wells
and 4 light crude oil wells were drilled. Another 29 wells
targeting light crude oil were drilled outside the Northern Plains
region.
Due to significant changes in relative commodity prices between
crude oil and natural gas during the first quarter of 2008, the
Company continued to access its large crude oil drilling inventory
to maximize value in both the short and long term. Due to the
Company's focus on drilling crude oil wells in 2007 and 2008,
natural gas drilling activities have been reduced to manage overall
capital spending. Deferred natural gas well locations have been
retained in the Company's prospect inventory.
As part of the phased expansion of its In-Situ Oil Sands Assets,
the Company is continuing to develop its Primrose thermal projects.
Overall Primrose thermal production for the first quarter of 2008
averaged approximately 69,000 bbl/d compared to approximately
58,000 bbl/d for the first quarter of 2007 and approximately 74,000
bbl/d for the prior quarter.
The Primrose East Expansion, a new facility located 15
kilometers from the existing Primrose South steam plant and 25
kilometers from the Wolf Lake central processing facility, is
anticipated to add approximately 40,000 bbl/d when complete.
Drilling and construction are currently underway, and production is
targeted to commence in 2009.
The next phase of the Company's In-Situ Oil Sands Assets
expansion is the Kirby project located 120 kilometers north of the
existing Primrose facilities. The Kirby project is anticipated to
add approximately 45,000 bbl/d of production growth. During 2007,
the Company filed a combined application and Environmental Impact
Assessment for this project with Alberta Environment and the
Alberta Energy and Utilities Board. Final corporate sanction and
project scope will be impacted by environmental regulations and
their associated costs.
Development of new pads and secondary recovery conversion
projects at Pelican Lake continued as expected throughout the first
quarter of 2008. Drilling consisted of 25 horizontal wells in the
first quarter. The response from the water and polymer flood
projects continues to be positive. Pelican Lake production averaged
approximately 37,000 bbl/d for the first quarter of 2008 compared
to 32,000 bbl/d for the first quarter of 2007 and approximately
36,000 bbl/d for the prior quarter.
For the second quarter of 2008, the Company's overall drilling
activity in North America is expected to be comprised of 8 natural
gas wells and 62 crude oil wells excluding stratigraphic and
service wells.
Horizon Project
Work progress on the Horizon Project was 94% complete at the end
of the first quarter. First production is targeted to commence in
the third quarter of 2008. The project status as at March 31, 2008
was as follows:
- Site assembly of Mine Operations equipment (Shovels and Heavy
Haul Trucks) is on schedule;
- Fixed Plant Maintenance contractors have been mobilized;
- All oversized loads for construction have been delivered to
site. Ongoing deliveries of mine equipment (trucks and shovels)
will continue through the summer;
- Overall construction 91% completed;
- Mine overburden removal has moved 56.7 million bank cubic
meters, which represents approximately 80% of the total to be moved
before start up;
- Completed Tar River Diversion and Fish Habitat
construction;
- Substantially completed Extraction Plant in the first quarter
and have introduced water to the plant in April;
- Completed construction of Tanks 11 and 12 in the East Tank
Farm and filled with diluent for start up;
- Installed 3 nitrogen storage tanks and completed construction
of the Nitrogen Plant, now ready for operations;
- Installed Auxiliary Boiler in Cogeneration;
- Assumed occupancy of Main Warehouse;
- Substations energized for Sulphur Recovery and Gas Treating,
representing the last on-site substations to be energized;
- Substantially completed construction of Amine Plant and moving
into Pre-Commissioning;
- Started construction of Sulphur pipeline;
- Completed piping in Heat Integration.
The Company has budgeted construction costs of approximately
$1.1 billion to $1.3 billion for the remainder of 2008 related to
the planned completion of Phase 1 of the Horizon Project.
North Sea
In the first quarter of 2008, the Company continued with its
planned program of infill drilling, recompletions, workovers and
waterflood optimizations. During the quarter, 1.6 net wells were
drilled, with an additional 1.6 net wells drilling at the end of
the quarter.
At Ninian, the Company continued with its planned investment in
its long-term facilities and infrastructure strategy. One well was
converted to water injection during the quarter and a further water
injection well is drilling and due for completion in the second
quarter. At the Murchison Platform, the first of 2 production wells
planned for 2008 was completed, with the second scheduled for
completion in the second quarter. At Columba E, the Company
successfully increased water injection rates, thereby increasing
reservoir pressure with the goal of increasing production.
Offshore West Africa
During the first quarter of 2008, 0.6 net wells were
drilled.
Crude oil production from West Espoir commenced in mid 2006 with
the final production well in the program added during the first
quarter of 2008. The drilling program was completed on budget and
on schedule.
At the 90% owned and operated Olowi Field in offshore Gabon, all
major construction contracts have been awarded and construction
activity on the wellhead towers, subsea facilities and the floating
production storage and offtake vessel ("FPSO") are progressing as
planned. Drilling commenced early in the second quarter of 2008 and
first crude oil is targeted for late 2008. Olowi production is
targeted to plateau at approximately 20,000 bbl/d net to the
Company.
LIQUIDITY AND CAPITAL RESOURCES
Mar 31 Dec 31 Mar 31
($ millions, except ratios) 2008 2007 2007
----------------------------------------------------------------------------
Working capital deficit (1) $ 1,572 $ 1,382 $ 1,104
Long-term debt (2) $ 11,230 $ 10,940 $ 11,307
Share capital $ 2,725 $ 2,674 $ 2,635
Retained earnings 11,248 10,575 8,374
Accumulated other comprehensive
income (loss) 95 72 (45)
----------------------------------------------------------------------------
Shareholders' equity $ 14,068 $ 13,321 $ 10,964
Debt to book capitalization (2)(3) 44% 45% 51%
Debt to market capitalization (2)(4) 23% 22% 25%
After tax return on average common
shareholders' equity (5) 24% 22% 28%
After tax return on average capital
employed (2) (6) 14% 12% 17%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated as current assets less current liabilities.
(2) Long-term debt is stated at its carrying value, net of fair value
adjustments, original issue discounts and transaction costs.
(3) Calculated as long-term debt; divided by the book value of common
shareholders' equity plus long-term debt.
(4) Calculated as long-term debt; divided by the market value of common
shareholders' equity plus long-term debt.
(5) Calculated as net earnings for the twelve month trailing period; as a
percentage of average common shareholders' equity for the period.
(6) Calculated as net earnings plus after-tax interest expense for the
twelve month trailing period; as a percentage of average capital
employed for the period. Average capital employed is the average
shareholders' equity and long-term debt for the period, including $7,876
million in average capital employed related to the Horizon Project
(December 31, 2007 - $7,001 million; March 31, 2007 - $4,507 million).
The Company's capital resources at March 31, 2008 consisted
primarily of cash flow from operations, available credit facilities
and access to debt capital markets. Cash flow from operations is
dependent on factors discussed in the "Risks and Uncertainties"
section of the Company's December 31, 2007 annual MD&A. The
Company's ability to renew existing credit facilities and raise new
debt is also dependent upon these factors, as well as maintaining
an investment grade debt rating and the condition of capital and
credit markets. Management believes internally generated cash flows
supported by the implementation of the Company's hedge policy, the
flexibility of its capital expenditure programs supported by its
multi-year financial plans, the Company's existing credit
facilities and the Company's ability to raise new debt on
commercially acceptable terms, will be sufficient to sustain its
operations and support its growth strategy. The Company's current
debt ratings are BBB (high) with a negative trend by DBRS Limited,
Baa2 with a stable outlook by Moody's Investors Service and BBB
with a stable outlook by Standard & Poor's. The Company does
not have any direct exposure to asset-backed commercial paper.
At March 31, 2008, the Company had undrawn bank lines of credit
of $2,626 million. Details related to the Company's long-term debt
at March 31, 2008 are disclosed in note 3 to the Company's
unaudited interim consolidated financial statements.
At March 31, 2008, the Company's working capital deficit was
$1,572 million and included the current portion of the stock-based
compensation liability of $342 million and the current portion of
the net mark-to-market liability for risk management derivative
financial instruments of $1,365 million. The settlement of the
stock-based compensation liability is dependent upon both the
surrender of vested stock options for cash settlement by employees
and the value of the Company's share price at the time of
surrender. The cash settlement amount of the risk management
derivative financial instruments may vary materially depending upon
the underlying crude oil and natural gas prices at the time of
final settlement of the derivative financial instruments, as
compared to their mark-to-market value at March 31, 2008.
The Company believes it has the necessary financial capacity to
complete the Horizon Project, while at the same time not
compromising conventional crude oil and natural gas growth
opportunities. The financing of Phase 1 of the Horizon Project
development is guided by the competing principles of retaining as
much direct ownership interest as possible while maintaining a
strong balance sheet.
Long-term debt was $11,230 million at March 31, 2008, resulting
in a debt to book capitalization ratio of 44% (December 31, 2007 -
45%; March 31, 2007 - 51%). While this ratio is at the high end of
the 35% to 45% range targeted by management, the Company remains
committed to maintaining a strong balance sheet and flexible
capital structure, and expects its debt to book capitalization
ratio to be near the midpoint of the range in late 2008. While the
Company believes that it has the balance sheet strength and
flexibility to complete Phase 1 of the Horizon Project, as well as
its other planned capital expenditure programs, the Company has
hedged a significant portion of its crude oil and natural gas
production for 2008 at prices that protect investment returns. In
the future, the Company may also consider the divestiture of
certain non-strategic and non-core properties to gain additional
balance sheet flexibility.
The Company's commodity hedging program reduces the risk of
volatility in commodity price markets and supports the Company's
cash flow for its capital expenditures throughout the Horizon
Project construction period. This program currently allows for the
hedging of up to 75% of the near 12 months budgeted production, up
to 50% of the following 13 to 24 months estimated production and up
to 25% of production expected in months 25 to 48. For the purpose
of this program, the purchase of put options is in addition to the
above parameters. In accordance with the policy, approximately 61%
of budgeted crude oil volumes are hedged for the remainder of 2008,
approximately 18% of budgeted natural gas volumes are hedged for
the second and third quarters of 2008 and approximately 6% of
estimated crude oil volumes are hedged for 2009. In addition,
50,000 bbl/d of crude oil volumes are protected by put options for
the remainder of 2008 at a strike price of US$55.00 per barrel and
50,000 bbl/d of crude oil volumes are protected by put options for
2009 at a strike price of US$80.00 per barrel.
Commencing January 1, 2009, following the planned completion of
Phase 1 of the Horizon Project, the Company's commodity hedging
program has been revised by its Board of Directors to allow for the
hedging of up to 50% of the near 12 months budgeted production and
up to 25% of the following 13 to 24 months estimated production.
The purchase of put options will continue to be in addition to the
above parameters.
The Company has the following commodity related net financial derivatives
outstanding as at March 31, 2008:
Remaining term Volume Weighted Index
average price
----------------------------------------------------------------------------
Crude oil
Crude oil price
collars Apr 2008-Jun 2008 25,000 bbl/d US$60.00-US$80.44 WTI
Apr 2008-Sep 2008 25,000 bbl/d US$60.00-US$80.46 WTI
Jul 2008-Sep 2008 25,000 bbl/d US$70.00-US$123.75 WTI
Mayan
Apr 2008-Dec 2008 20,000 bbl/d US$50.00-US$65.53 Heavy
Apr 2008-Dec 2008 50,000 bbl/d US$60.00-US$75.22 WTI
Apr 2008-Dec 2008 50,000 bbl/d US$60.00-US$76.05 WTI
Apr 2008-Dec 2008 50,000 bbl/d US$60.00-US$76.98 WTI
Oct 2008-Dec 2008 25,000 bbl/d US$70.00-US$112.63 WTI
Jan 2009-Dec 2009 25,000 bbl/d US$70.00-US$111.56 WTI
Crude oil puts Apr 2008-Dec 2008 50,000 bbl/d US$55.00 WTI
Jan 2009-Dec 2009 50,000 bbl/d US$80.00 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural gas
AECO price
collars Apr 2008-Sep 2008 290,000 GJ/d C$7.50-C$8.69 AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's outstanding commodity financial derivatives are
expected to be settled monthly based on the applicable index
pricing for the respective contract month.
Long-term debt
As at March 31, 2008, the Company had in place unsecured bank
credit facilities of $6,211 million, comprised of:
- a $100 million demand credit facility;
- a non-revolving syndicated credit facility of $2,350 million
maturing October 2009;
- a revolving syndicated credit facility of $2,230 million
maturing June 2012;
- a revolving syndicated credit facility of $1,500 million
maturing June 2012; and
- a Pounds Sterling 15 million demand credit facility related to
the Company's North Sea operations.
The revolving syndicated credit facilities are extendible
annually for one year periods at the mutual agreement of the
Company and the lenders. If the facilities are not extended, the
full amount of the outstanding principal would be repayable on the
maturity date.
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $351 million, including $300
million related to the Horizon Project, were outstanding at March
31, 2008.
Medium-term notes
The Company has $2,600 million remaining on its outstanding
$3,000 million base shelf prospectus filed in September 2007 that
allows for the issue of medium-term notes in Canada until October
2009. If issued, these securities will bear interest as determined
at the date of issuance.
US dollar debt securities
In January 2008, the Company issued US$1,200 million of
unsecured notes under a US base shelf prospectus, comprised of
US$400 million of 5.15% unsecured notes due February 2013, US$400
million of 5.90% unsecured notes due February 2018, and US$400
million of 6.75% unsecured notes due February 2039. Proceeds from
the securities issued were used to repay bankers' acceptances under
the Company's bank credit facilities. After issuing these
securities, the Company has US$1,800 million remaining on its
outstanding US$3,000 million base shelf prospectus filed in
September 2007 that allows for the issue of US dollar debt
securities in the United States until October 2009. If issued,
these securities will bear interest as determined at the date of
issuance.
Share capital
As at March 31, 2008, there were 540,465,000 common shares
outstanding and 27,835,000 stock options outstanding. As at May 6,
2008, the Company had 540,543,000 common shares outstanding and
26,659,000 stock options outstanding.
The Company did not purchase any common shares for cancellation
pursuant to the Normal Course Issuer Bid previously filed for the
twelve month period beginning January 24, 2007 and ending January
23, 2008. The Company has decided not to renew the Normal Course
Issuer Bid until subsequent to the completion of Phase 1 of the
Horizon Project.
In February 2008, the Company's Board of Directors approved an
increase in the annual dividend paid by the Company to $0.40 per
common share for 2008. The increase represents an 18% increase from
2007, recognizes the stability of the Company's cash flow, and
provides a return to Shareholders. This is the eighth consecutive
year in which the Company has paid dividends and the seventh
consecutive year of an increase in the distribution paid to its
Shareholders. The dividend policy undergoes a periodic review by
the Board of Directors and is subject to change.
Commitments and off balance sheet arrangements
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. These commitments primarily relate to debt
repayments; operating leases relating to offshore FPSOs, drilling
rigs and office space; firm commitments for gathering, processing
and transmission services; as well as expenditures relating to
asset retirement obligations. As at March 31, 2008, no entities
were consolidated under the Canadian Institute of Chartered
Accountants Handbook Accounting Guideline 15, "Consolidation of
Variable Interest Entities". The following table summarizes the
Company's commitments as at March 31, 2008:
Remaining
($ millions) 2008 2009 2010 2011 2012 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 180 $ 163 $ 149 $ 123 $ 107 $ 1,099
Offshore equipment
operating lease (1) $ 98 $ 130 $ 118 $ 116 $ 94 $ 405
Offshore drilling (2)(3) $ 274 $ 187 $ 47 $ - $ - $ -
Asset retirement
obligations (4) $ 28 $ 4 $ 5 $ 4 $ 4 $ 4,484
Long-term debt (5) $ 40 $ 2,374 $ 400 $ 411 $ 360 $ 6,505
Interest expense (6) $ 429 $ 586 $ 499 $ 477 $ 424 $ 5,390
Office lease $ 19 $ 26 $ 29 $ 22 $ 2 $ -
Electricity and other $ 126 $ 267 $ 162 $ 4 $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Offshore equipment operating leases are primarily comprised of
obligations related to FPSOs. During 2006, the Company entered into an
agreement to lease an additional FPSO commencing in 2008, in connection
with the planned offshore development in Gabon, Offshore West Africa.
During the initial term, the total annual payments for the Gabon FPSO
are estimated to be US$50 million.
(2) During 2007, the Company entered into a one-year agreement for offshore
drilling services related to the Baobab Field in Cote d'Ivoire, Offshore
West Africa. The agreement is scheduled to commence in the second
quarter of 2008, on delivery of the rig. Estimated total payments of
US$100 million, after joint venture recoveries, have been included in
this table for the period 2008 - 2009.
(3) During 2007, the Company awarded contracts for a drilling rig and for
the construction of wellhead towers in connection with the planned
offshore development in Gabon, Offshore West Africa. Estimated total
payments of US$392 million have been included in this table for the
period 2008 - 2010.
(4) Amounts represent management's estimate of the future undiscounted
payments to settle asset retirement obligations related to resource
properties, facilities, and production platforms, based on current
legislation and industry operating practices. Amounts disclosed for the
period 2008 - 2012 represent the minimum required expenditures to meet
these obligations. Actual expenditures in any particular year may exceed
these minimum amounts.
(5) The long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or transaction
costs. No debt repayments are reflected for $1,182 million of revolving
bank credit facilities due to the extendable nature of the facilities.
(6) Interest expense amounts represent the scheduled fixed-rate and
variable-rate cash payments related to long-term debt. Interest on
variable-rate long term debt was estimated based upon prevailing
interest rates as at March 31, 2008.
In addition to the amounts disclosed above, the Company has
budgeted construction costs of approximately $1.1 billion to $1.3
billion for the remainder of 2008 related to the planned completion
of Phase 1 of the Horizon Project.
Legal proceedings
The Company is defendant and plaintiff in a number of legal
actions that arise in the normal course of business. In addition,
the Company is subject to certain contractor construction claims
related to the Horizon Project. The Company believes that any
liabilities that might arise pertaining to any such matters would
not have a material effect on its consolidated financial
position.
Critical accounting estimates and change in accounting
policies
The preparation of financial statements requires the Company to
make judgements, assumptions and estimates in the application of
generally accepted accounting principles that have a significant
impact on the financial results of the Company. Actual results
could differ from those estimates. A comprehensive discussion of
the Company's significant accounting policies is contained in the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2007.
For the impact of new accounting standards related to capital
disclosures, inventory and financial instruments, refer to note 2
of the unaudited interim consolidated financial statements as at
March 31, 2008.
SENSITIVITY ANALYSIS
The following table is indicative of the annualized
sensitivities of cash flow from operations and net earnings from
changes in certain key variables. The analysis is based on business
conditions and sales volumes during the first quarter of 2008,
excluding mark-to-market gains (losses) on risk management
activities, and is not necessarily indicative of future results.
Each separate line item in the sensitivity analysis shows the
effect of a change in that variable only with all other variables
being held constant.
Cash flow Cash flow from Net
from operations Net earnings
operations (per common earnings (per common
($ millions) share, basic) ($ millions) share, basic)
----------------------------------------------------------------------------
Price changes
Crude oil -
WTI US$1.00/bbl
(1)
Excluding
financial
derivatives $ 95 $ 0.18 $ 70 $ 0.13
Including
financial
derivatives $ 40 $ 0.07 $ 31 $ 0.06
Natural gas-
AECO
C$0.10/mcf
(1)
Excluding
financial
derivatives $ 40 $ 0.07 $ 28 $ 0.05
Including
financial
derivatives $ 35 $ 0.06 $ 25 $ 0.05
Volume changes
Crude oil -
10,000 bbl/d $ 177 $ 0.33 $ 106 $ 0.20
Natural gas -
10 mmcf/d $ 20 $ 0.04 $ 9 $ 0.02
Foreign currency
rate change
$0.01 change
in US$ (1)
Including
financial
derivatives $ 87 - 89 $ 0.16 $ 30 $ 0.05 - 0.06
Interest rate
change - 1% $ 30 $ 0.06 $ 30 $ 0.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) For details of outstanding financial instruments in place, refer to note
10 of the Company's unaudited interim consolidated financial statements.
OTHER OPERATING HIGHLIGHTS
NETBACK ANALYSIS
Three Months Ended
---------------------------------------
Mar 31 Dec 31 Mar 31
($/boe) (1) 2008 2007 2007
----------------------------------------------------------------------------
Sales price (2) $ 65.09 $ 49.23 $ 49.32
Royalties 8.43 6.21 6.76
Production expense (3) 11.02 8.85 10.10
----------------------------------------------------------------------------
Netback 45.64 34.17 32.46
Midstream contribution (3) (0.27) (0.24) (0.24)
Administration 0.80 0.76 1.08
Interest, net 0.92 0.92 1.49
Realized risk management loss (gain) 7.82 3.27 (1.58)
Realized foreign exchange (gain)
loss (0.22) - 0.10
Taxes other than income tax -
current 1.32 0.30 1.18
Current income tax - North America 0.40 0.56 0.45
Current income tax - North Sea 1.79 1.18 0.62
Current income tax - Offshore West
Africa 0.71 0.50 0.18
----------------------------------------------------------------------------
Cash flow $ 32.37 $ 26.92 $ 29.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
(3) Excluding intersegment elimination.
FINANCIAL STATEMENTS
Consolidated Balance Sheets
Mar 31 Dec 31
(millions of Canadian dollars, unaudited) 2008 2007
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 27 $ 21
Accounts receivable and other 2,135 1,662
Future income tax 506 480
Current portion of other long-term assets - 18
----------------------------------------------------------------------------
2,668 2,181
Property, plant and equipment (note 12) 35,051 33,902
Other long-term assets 36 31
----------------------------------------------------------------------------
$ 37,755 $ 36,114
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 455 $ 379
Accrued liabilities 2,078 1,567
Current portion of other long-term
liabilities (note 4) 1,707 1,617
----------------------------------------------------------------------------
4,240 3,563
Long-term debt (note 3) 11,230 10,940
Other long-term liabilities (note 4) 1,386 1,561
Future income tax 6,831 6,729
----------------------------------------------------------------------------
23,687 22,793
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (note 6) 2,725 2,674
Retained earnings 11,248 10,575
Accumulated other comprehensive income (note 7) 95 72
----------------------------------------------------------------------------
14,068 13,321
----------------------------------------------------------------------------
$ 37,755 $ 36,114
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (note 11)
Consolidated Statements of Earnings
Three Months Ended
(millions of Canadian dollars, except per common Mar 31 Mar 31
share amounts, unaudited) 2008 2007
----------------------------------------------------------------------------
Revenue $ 3,967 $ 3,118
Less: royalties (449) (376)
----------------------------------------------------------------------------
Revenue, net of royalties 3,518 2,742
----------------------------------------------------------------------------
Expenses
Production 587 565
Transportation and blending 485 359
Depletion, depreciation and amortization 688 709
Asset retirement obligation accretion (note 4) 17 18
Administration 43 60
Stock-based compensation expense (note 4) - 25
Interest, net 49 83
Risk management activities (note 10) 524 448
Foreign exchange loss (gain) 114 (27)
----------------------------------------------------------------------------
2,507 2,240
----------------------------------------------------------------------------
Earnings before taxes 1,011 502
Taxes other than income tax 49 63
Current income tax expense (note 5) 155 70
Future income tax expense (note 5) 80 100
----------------------------------------------------------------------------
Net earnings $ 727 $ 269
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common share (note 9)
Basic and diluted $ 1.35 $ 0.50
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Shareholders' Equity
Three Months Ended
Mar 31 Mar 31
(millions of Canadian dollars, unaudited) 2008 2007
----------------------------------------------------------------------------
Share capital (note 6)
Balance - beginning of period $ 2,674 $ 2,562
Issued upon exercise of stock options 9 13
Previously recognized liability on stock options
exercised for common shares 42 60
----------------------------------------------------------------------------
Balance - end of period 2,725 2,635
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of period 10,575 8,151
Net earnings 727 269
Dividends on common shares (note 6) (54) (46)
----------------------------------------------------------------------------
Balance - end of period 11,248 8,374
----------------------------------------------------------------------------
Accumulated other comprehensive income (loss)
(note 7)
Balance - beginning of period 72 146
Other comprehensive income (loss), net of taxes 23 (191)
----------------------------------------------------------------------------
Balance - end of period 95 (45)
----------------------------------------------------------------------------
Shareholders' equity $ 14,068 $ 10,964
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income
Three Months Ended
Mar 31 Mar 31
(millions of Canadian dollars, unaudited) 2008 2007
----------------------------------------------------------------------------
Net earnings $ 727 $ 269
----------------------------------------------------------------------------
Net change in derivative financial instruments
designated as cash flow hedges
Unrealized income during the period, net of taxes
of $2 million (2007 - $55 million) 24 (116)
Reclassification to net earnings, net of taxes of
$8 million (2007 - $35 million) (17) (74)
----------------------------------------------------------------------------
7 (190)
Foreign currency translation adjustment
Translation of net investment 16 (1)
----------------------------------------------------------------------------
Other comprehensive income (loss), net of taxes 23 (191)
----------------------------------------------------------------------------
Comprehensive income $ 750 $ 78
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Three Months Ended
Mar 31 Mar 31
(millions of Canadian dollars, unaudited) 2008 2007
----------------------------------------------------------------------------
Operating activities
Net earnings $ 727 $ 269
Non-cash items
Depletion, depreciation and amortization 688 709
Asset retirement obligation accretion 17 18
Stock-based compensation expense - 25
Unrealized risk management loss 108 536
Unrealized foreign exchange loss (gain) 126 (32)
Deferred petroleum revenue tax recovery (21) (3)
Future income tax expense 80 100
Other 13 (13)
Abandonment expenditures (6) (20)
Net change in non-cash working capital (166) (119)
----------------------------------------------------------------------------
1,566 1,470
----------------------------------------------------------------------------
Financing activities
Repayment of bank credit facilities, net (1,172) (2,013)
Repayment of medium-term notes - (125)
Issue of US dollar debt securities 1,223 2,553
Issue of common shares on exercise of stock options 9 13
Dividends on common shares (46) (40)
Net change in non-cash working capital 5 (22)
----------------------------------------------------------------------------
19 366
----------------------------------------------------------------------------
Investing activities
Expenditures on property, plant and equipment (1,756) (1,993)
Net proceeds on sale of property, plant and equipment 9 4
----------------------------------------------------------------------------
Net expenditures on property, plant and equipment (1,747) (1,989)
Net change in non-cash working capital 168 144
----------------------------------------------------------------------------
(1,579) (1,845)
----------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents 6 (9)
Cash and cash equivalents - beginning of period 21 23
----------------------------------------------------------------------------
Cash and cash equivalents - end of period $ 27 $ 14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 146 $ 158
Taxes paid
Taxes other than income tax $ 31 $ 35
Current income tax $ 53 $ 71
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes to the consolidated financial statements
(tabular amounts in millions of Canadian dollars, unless
otherwise stated, unaudited)
1. ACCOUNTING POLICIES
The interim consolidated financial statements of Canadian
Natural Resources Limited (the "Company") include the Company and
all of its subsidiaries and partnerships, and have been prepared
following the same accounting policies as the audited consolidated
financial statements of the Company as at December 31, 2007, except
as described in note 2. The interim consolidated financial
statements contain disclosures that are supplemental to the
Company's annual audited consolidated financial statements. Certain
disclosures that are normally required to be included in the notes
to the annual audited consolidated financial statements have been
condensed. These interim financial statements should be read in
conjunction with the Company's audited consolidated financial
statements and notes thereto for the year ended December 31,
2007.
Comparative Figures
Certain prior period figures have been reclassified to conform
to the presentation adopted in 2008.
2. CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2008 the Company adopted the following
accounting and disclosure standards issued by the Canadian
Institute of Chartered Accountants:
- Capital Disclosures - Section 1535 - "Capital Disclosures"
requires entities to disclose their objectives, policies and
processes for managing capital, as well as quantitative data about
capital. The standard also requires the disclosure of any
externally imposed capital requirements and compliance with those
requirements. The standard does not define capital. This standard
affects disclosure only and did not impact the Company's accounting
for capital (note 8).
- Inventories - Section 3031 - "Inventories" replaces Section
3030 - "Inventories" and establishes new standards for the
measurement of cost of inventories and expands disclosure
requirements for inventories. Adoption of this standard did not
have a material impact on the Company's financial statements.
- Financial Instruments - Section 3862 - "Financial Instruments
- Disclosure" and Section 3863 - "Financial Instruments -
Presentation" replace Section 3861 - "Financial Instruments -
Disclosure and Presentation". Section 3862 enhances disclosure
requirements concerning risks and requires quantitative and
qualitative disclosures about exposures to risks arising from
financial instruments. Section 3863 carries forward the
presentation requirements from Section 3861 unchanged. These
standards affect disclosures only and do not impact the Company's
accounting for financial instruments (note 10).
3. LONG-TERM DEBT
-------------------------
Mar 31 Dec 31
2008 2007
---------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities (bankers' acceptances) $ 3,524 $ 4,696
Medium-term notes 1,200 1,200
---------------------------------------------------------------------------
4,724 5,896
---------------------------------------------------------------------------
US dollar denominated debt
Senior unsecured notes
(2008 - US$62 million; 2007 - US$62 million) 64 61
US dollar debt securities
(2008 - US$6,308 million; 2007 - US$5,108 million) 6,484 5,048
Less - original issue discount on senior unsecured
notes and US dollar debt securities (1) (24) (23)
---------------------------------------------------------------------------
6,524 5,086
Fair value of interest rate swaps on US dollar
debt securities (2) 41 9
---------------------------------------------------------------------------
6,565 5,095
---------------------------------------------------------------------------
Long-term debt before transaction costs 11,289 10,991
Less - transaction costs (1) (3) (59) (51)
---------------------------------------------------------------------------
$ 11,230 $ 10,940
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) The Company has included unamortized original issue discounts and
directly attributable transaction costs in the carrying value of the
outstanding debt.
(2) The carrying values of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been adjusted
by $41 million (2007 - $9 million) to reflect the fair value impact of
hedge accounting.
(3) Transaction costs primarily represent underwriting commissions charged
as a percentage of the related debt offerings, as well as legal, rating
agency and other professional fees.
Bank credit facilities
As at March 31, 2008, the Company had in place unsecured bank
credit facilities of $6,211 million, comprised of:
- a $100 million demand credit facility;
- a non-revolving syndicated credit facility of $2,350 million
maturing October 2009;
- a revolving syndicated credit facility of $2,230 million
maturing June 2012;
- a revolving syndicated credit facility of $1,500 million
maturing June 2012; and
- a Pounds Sterling 15 million demand credit facility related to
the Company's North Sea operations.
The revolving syndicated credit facilities are extendible
annually for one year periods at the mutual agreement of the
Company and the lenders. If the facilities are not extended, the
full amount of the outstanding principal would be repayable on the
maturity date.
The weighted average interest rate of the bank credit facilities
outstanding at March 31, 2008, was 4.3% (December 31, 2007 -
5.2%).
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $351 million, including $300
million related to the Horizon Oil Sands Project ("Horizon
Project"), were outstanding at March 31, 2008.
Medium-term notes
The Company has $2,600 million remaining on its outstanding
$3,000 million base shelf prospectus filed in September 2007 that
allows for the issue of medium-term notes in Canada until October
2009. If issued, these securities will bear interest as determined
at the date of issuance.
US dollar debt securities
In January 2008, the Company issued US$1,200 million of
unsecured notes under a US base shelf prospectus, comprised of
US$400 million of 5.15% unsecured notes due February 2013, US$400
million of 5.90% unsecured notes due February 2018, and US$400
million of 6.75% unsecured notes due February 2039. Proceeds from
the securities issued were used to repay bankers' acceptances under
the Company's bank credit facilities. After issuing these
securities, the Company has US$1,800 million remaining on its
outstanding US$3,000 million base shelf prospectus filed in
September 2007 that allows for the issue of US dollar debt
securities in the United States until October 2009. If issued,
these securities will bear interest as determined at the date of
issuance.
4. OTHER LONG-TERM LIABILITIES
-------------------------
Mar 31 Dec 31
2008 2007
---------------------------------------------------------------------------
Asset retirement obligations $ 1,110 $ 1,074
Stock-based compensation 402 529
Risk management (note 10) 1,479 1,474
Other 102 101
---------------------------------------------------------------------------
3,093 3,178
Less: current portion 1,707 1,617
---------------------------------------------------------------------------
$ 1,386 $ 1,561
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Asset retirement obligations
At March 31, 2008, the Company's total estimated undiscounted
costs to settle its asset retirement obligations were approximately
$4,529 million (December 31, 2007 - $4,426 million). These costs
will be incurred over the lives of the operating assets and have
been discounted using a weighted average credit-adjusted risk free
rate of 6.6% (December 31, 2007 - 6.6%). A reconciliation of the
discounted asset retirement obligations is as follows:
-----------------------------
Three Months Year
Ended Ended
Mar 31, 2008 Dec 31, 2007
---------------------------------------------------------------------------
Balance - beginning of period $ 1,074 $ 1,166
Liabilities incurred 9 21
Liabilities disposed - (65)
Liabilities settled (6) (71)
Asset retirement obligation accretion 17 70
Revision of estimates - 35
Foreign exchange 16 (82)
---------------------------------------------------------------------------
Balance - end of period $ 1,110 $ 1,074
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Stock-based compensation
The Company recognizes a liability for the potential cash
settlements under its Stock Option Plan. The current portion
represents the maximum amount of the liability payable within the
next twelve month period if all vested options are surrendered for
cash settlement.
-----------------------------
Three Months Year
Ended Ended
Mar 31, 2008 Dec 31, 2007
---------------------------------------------------------------------------
Balance - beginning of period $ 529 $ 744
Stock-based compensation - 193
Payments for options surrendered (80) (375)
Transferred to common shares (42) (91)
(Recovery) capitalized to Horizon Project (5) 58
---------------------------------------------------------------------------
Balance - end of period 402 529
Less: current portion 342 390
---------------------------------------------------------------------------
$ 60 $ 139
---------------------------------------------------------------------------
---------------------------------------------------------------------------
5. INCOME TAXES
The provision for income taxes is as follows:
-------------------------
Three Months Ended
Mar 31 Mar 31
2008 2007
---------------------------------------------------------------------------
Current income tax - North America $ 21 $ 25
Current income tax - North Sea 96 35
Current income tax - Offshore West Africa 38 10
---------------------------------------------------------------------------
Current income tax expense 155 70
Future income tax expense 80 100
---------------------------------------------------------------------------
Income tax expense $ 235 $ 170
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Taxable income from the conventional crude oil and natural gas
business in Canada is primarily generated through partnerships,
with the related income taxes payable in a future period. North
America current income taxes have been provided on the basis of the
corporate structure and available income tax deductions and will
vary depending upon the nature, timing and amount of capital
expenditures incurred in Canada in any particular year.
During the first quarter of 2008, enacted or substantively
enacted income tax rate changes resulted in a reduction of future
income tax liabilities of approximately $19 million in British
Columbia and $22 million in Cote d'Ivoire, Offshore West
Africa.
6. SHARE CAPITAL
---------------------------------
Three Months Ended Mar 31, 2008
Number of
Issued shares
Common shares (thousands) Amount
---------------------------------------------------------------------------
Balance - beginning of period 539,729 $ 2,674
Issued upon exercise of stock options 736 9
Previously recognized liability on stock
options exercised for common shares - 42
---------------------------------------------------------------------------
Balance - end of period 540,465 $ 2,725
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Normal Course Issuer Bid
The Company did not purchase any common shares for cancellation
pursuant to the Normal Course Issuer Bid previously filed for the
twelve month period beginning January 24, 2007 and ending January
23, 2008. The Company has not renewed the Normal Course Issuer Bid
in 2008.
Dividend policy
In February 2008, the Board of Directors set the regular
quarterly dividend at $0.10 per common share. The Company has paid
regular quarterly dividends in January, April, July, and October of
each year since 2001. The dividend policy undergoes a periodic
review by the Board of Directors and is subject to change.
Stock options
---------------------------------
Three Months Ended Mar 31, 2008
Weighted
Stock average
options exercise
(thousands) price
---------------------------------------------------------------------------
Outstanding - beginning of period 30,659 $ 47.23
Granted 346 $ 72.14
Surrendered for cash settlement (1,558) $ 22.68
Exercised for common shares (736) $ 11.94
Forfeited (876) $ 53.35
---------------------------------------------------------------------------
Outstanding - end of period 27,835 $ 49.65
---------------------------------------------------------------------------
Exercisable - end of period 8,108 $ 34.27
---------------------------------------------------------------------------
---------------------------------------------------------------------------
7. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The components of accumulated other comprehensive income (loss), net of
taxes, were as follows:
-------------------------
Three Months Ended
Mar 31 Mar 31
2008 2007
---------------------------------------------------------------------------
Derivative financial instruments designated
as cash flow hedges $ 108 $ (31)
Foreign currency translation adjustment (13) (14)
---------------------------------------------------------------------------
$ 95 $ (45)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
8. CAPITAL DISCLOSURES
As required by Canadian generally accepted accounting principles
("GAAP"), effective January 1, 2008, the Company must provide
certain disclosures regarding its objectives, policies and
processes for managing capital, as well as provide certain
quantitative data about capital. As the Company does not have any
externally imposed capital requirements, for the purposes of this
disclosure, the Company has defined its capital to mean its
long-term debt and consolidated shareholders' equity, as determined
each reporting date.
The Company's objectives when managing its capital structure are
to maintain financial flexibility and balance to enable the Company
to access capital markets to sustain its on-going operations and to
support its growth strategies. The Company primarily monitors
capital on the basis of an internally derived non-GAAP financial
measure referred to as its "debt to book capitalization ratio",
which is the arithmetic ratio of long-term debt divided by the sum
of the carrying value of shareholders' equity plus long-term debt.
The Company aims over time to maintain its debt to book
capitalization ratio in the range of 35% to 45%. However, the
Company may exceed the high end of such target range if it is
investing in capital projects, undertaking acquisitions, or in
periods of lower commodity prices. The Company may be below the low
end of the target range when cash flow from operating activities is
greater than current investment activities. The ratio is currently
at the high end of the target range due to the debt financing of a
business acquisition in 2006 and the construction of the Horizon
Project.
Readers are cautioned that as the debt to book capitalization
ratio has no defined meaning under GAAP, this financial measure may
not be comparable to similar measures provided by other reporting
entities. Further, there can be no assurances that the Company will
continue to use this measure to monitor capital or will not alter
the method of calculation of this measure at some point in the
future.
-----------------------------
Mar 31 Dec 31
2008 2007
---------------------------------------------------------------------------
Long-term debt $ 11,230 $ 10,940
Total shareholders' equity $ 14,068 $ 13,321
Debt to book capitalization 44% 45%
---------------------------------------------------------------------------
---------------------------------------------------------------------------
9. NET EARNINGS PER COMMON SHARE
-------------------------
Three Months Ended
Mar 31 Mar 31
2008 2007
---------------------------------------------------------------------------
Weighted average common shares outstanding
(thousands) - basic and diluted 540,218 538,890
---------------------------------------------------------------------------
Net earnings - basic and diluted $ 727 $ 269
---------------------------------------------------------------------------
Net earnings per common share - basic and diluted $ 1.35 $ 0.50
---------------------------------------------------------------------------
---------------------------------------------------------------------------
10. FINANCIAL INSTRUMENTS
The carrying values of the Company's financial instruments by
category are as follows:
----------------------------------------------
Mar 31, 2008
---------------------------------------------------------------------------
Loans and Held for Other financial
receivables at trading at liabilities at
Asset (liability) amortized cost fair value amortized cost
---------------------------------------------------------------------------
Cash and cash equivalents $ - $ 27 $ -
Accounts receivable 1,615 - -
Accounts payable - - (455)
Accrued liabilities - - (2,078)
Risk management - (1,479) -
Long-term debt - - (11,230)
---------------------------------------------------------------------------
$ 1,615 $ (1,452) $ (13,763)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Dec 31, 2007
---------------------------------------------------------------------------
Loans and Held for Other financial
receivables at trading at liabilities at
Asset (liability) amortized cost fair value amortized cost
---------------------------------------------------------------------------
Cash and cash equivalents $ - $ 21 $ -
Accounts receivable 1,143 - -
Accounts payable - - (379)
Accrued liabilities - - (1,567)
Risk management - (1,474) -
Long-term debt - - (10,940)
---------------------------------------------------------------------------
$ 1,143 $ (1,453) $ (12,886)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
The carrying value of the Company's financial instruments
approximates their fair value, except for fixed-rate long-term debt
as noted below:
----------------------------------------
Mar 31, 2008 Dec 31, 2007
---------------------------------------------------------------------------
Carrying Fair Carrying Fair
value value value value
---------------------------------------------------------------------------
Fixed-rate long-term debt (1) $ 7,706 $ 7,698 $ 6,244 $ 6,259
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) The carrying values of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been adjusted
by $41 million (2007 - $9 million) to reflect the fair value impact of
hedge accounting.
Risk management
The Company uses derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures.
These financial instruments are entered into solely for hedging
purposes and are not intended for trading or other speculative
purposes.
The estimated fair value of derivative financial instruments has
been determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values
determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows and discount
rates. In determining these assumptions, the Company has relied
primarily on external readily observable market inputs including
quoted commodity prices and volatility, interest rate yield curves,
and foreign exchange rates. The resulting fair value estimates may
not necessarily be indicative of the amounts that could be realized
or settled in a current market transaction and these differences
may be material.
The changes in estimated fair values of derivative financial
instruments included in the risk management asset (liability) were
recognized in the financial statements as follows:
-----------------------------------
Three Months Year
Ended Ended
Mar 31, 2008 Dec 31, 2007
---------------------------------------------------------------------------
Asset (liability) Risk management Risk management
mark-to-market mark-to-market
---------------------------------------------------------------------------
Balance - beginning of period $ (1,474) $ 128
Retained earnings effect of adoption of
financial instrument standards - 14
Net cost of outstanding put options 120 58
Net change in fair value of
outstanding derivative financial
instruments attributable to:
- Risk management activities (108) (1,400)
- Interest expense 32 9
- Foreign exchange 75 (350)
- Other comprehensive income (4) 125
---------------------------------------------------------------------------
(1,359) (1,416)
Add: Put premium financing obligations (1) (120) (58)
---------------------------------------------------------------------------
Balance - end of period (1,479) (1,474)
Less: current portion (1,365) (1,227)
---------------------------------------------------------------------------
$ (114) $ (247)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) The Company has negotiated payment of put option premiums with various
counterparties at the time of actual settlement of the respective
options. These obligations have been reflected in the net risk
management (liability) asset.
Net losses (gains) from risk management activities were as follows:
----------------------------
Three Months Ended
Mar 31 Mar 31
2008 2007
---------------------------------------------------------------------------
Net realized risk management loss (gain) $ 416 $ (88)
Net unrealized risk management loss 108 536
---------------------------------------------------------------------------
$ 524 $ 448
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Financial risk factors
a) Market risk
Market risk is the risk that the fair value or future cash flows
of a financial instrument will fluctuate because of changes in
market prices. The Company's market risk is comprised of commodity
price risk, interest rate risk, and foreign currency exchange
risk.
Commodity price risk
The Company uses commodity price financial derivatives to manage
its exposure to commodity price risk associated with the sale of
its future crude oil and natural gas production. As at March 31,
2008, the Company had the following net financial derivatives
outstanding to manage its commodity price exposures:
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Crude oil
Crude oil Apr 2008 - US$60.00 -
price collars Jun 2008 25,000 bbl/d US$80.44 WTI
Apr 2008 - US$60.00 -
Sep 2008 25,000 bbl/d US$80.46 WTI
Jul 2008 - US$70.00 -
Sep 2008 25,000 bbl/d US$123.75 WTI
Apr 2008 - US$50.00 -
Dec 2008 20,000 bbl/d US$65.53 Mayan Heavy
Apr 2008 - US$60.00 -
Dec 2008 50,000 bbl/d US$75.22 WTI
Apr 2008 - US$60.00 -
Dec 2008 50,000 bbl/d US$76.05 WTI
Apr 2008 - US$60.00 -
Dec 2008 50,000 bbl/d US$76.98 WTI
Oct 2008 - US$70.00 -
Dec 2008 25,000 bbl/d US$112.63 WTI
Jan 2009 - US$70.00 -
Dec 2009 25,000 bbl/d US$111.56 WTI
Crude oil puts Apr 2008 -
Dec 2008 50,000 bbl/d US$55.00 WTI
Jan 2009 -
Dec 2009 50,000 bbl/d US$80.00 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The net cost of outstanding put options and their respective periods of
settlement are as follows:
Q2 Q3 Q4 Q1 Q2 Q3 Q4
2008 2008 2008 2009 2009 2009 2009
----------------------------------------------------------------------------
Cost ($ millions) US$15 US$15 US$15 US$18 US$18 US$18 US$18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Natural gas
AECO price
collars Apr 2008 - Sep 2008 290,000 GJ/d C$7.50 - C$8.69 AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's outstanding commodity financial derivatives are
expected to be settled monthly based on the applicable index
pricing for the respective contract month.
Interest rate risk
The Company is exposed to interest rate risk on its fixed and
floating rate long-term debt. The Company enters into interest rate
swap agreements to manage its fixed to floating interest rate mix
on long-term debt. The interest rate swap contracts require the
periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. At March 31,
2008, the Company had the following interest rate swap contracts
outstanding:
Remaining Amount
term ($ millions) Fixed rate Floating rate
----------------------------------------------------------------------------
Interest rate
Swaps -
fixed to
floating Apr 2008 - Oct 2012 US$350 5.45% LIBOR (1) + 0.81%
Apr 2008 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) London Interbank Offered Rate
All interest rate related derivative financial instruments
designated as hedges at March 31, 2008 were classified as fair
value hedges.
Foreign currency exchange rate risk
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated debt. The
Company is also exposed to foreign currency exchange rate risk on
transactions conducted in foreign currencies in its foreign
subsidiaries and in the carrying value of its self-sustaining
foreign subsidiaries. The Company enters into cross currency swap
agreements to manage currency exposure on US dollar denominated
long-term debt. The cross currency swap contracts require the
periodic exchange of payments with the exchange at maturity of
notional principal amounts on which the payments are based. At
March 31, 2008, the Company had the following cross currency swap
contracts outstanding:
Exchange Interest Interest
Remaining Amount rate rate rate
term ($ millions) (US$/C$) (US$) (C$)
----------------------------------------------------------------------------
Cross
currency
Swaps Apr 2008 - Aug 2016 US$250 1.116 6.00% 5.40%
Apr 2008 - May 2017 US$1,100 1.170 5.70% 5.10%
Apr 2008 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All cross currency related derivative financial instruments
designated as hedges at March 31, 2008 were classified as cash flow
hedges.
Financial instrument sensitivities
The following table summarizes the annualized sensitivities of
the Company's net earnings and other comprehensive income to
changes in the fair value of financial instruments outstanding as
at March 31, 2008 resulting from changes in the specified variable,
with all other variables held constant. These sensitivities are
limited to the impact of changes in a specified variable applied to
financial instruments only and do not represent the impact of a
change in the variable on the operating results of the Company
taken as a whole. Further, these sensitivities are theoretical, as
changes in one variable may contribute to changes in another
variable, which may magnify or counteract the sensitivities. In
addition, changes in fair value generally can not be extrapolated
because the relationship of a change in an assumption to the change
in fair value may not be linear.
----------------------------------------------------------------------------
Impact on other
Impact on net comprehensive
earnings income
----------------------------------------------------------------------------
Commodity price risk
Increase WTI US$1.00/bbl $ (42) $ -
Decrease WTI US$1.00/bbl $ 42 $ -
Increase AECO C$0.10/mcf $ (2) $ -
Decrease AECO C$0.10/mcf $ 2 $ -
Interest rate risk
Increase interest rate 1% $ (19) $ 13
Decrease interest rate 1% $ 19 $ (15)
Foreign currency exchange rate risk
Increase exchange rate by US$0.01 $ (28) $ -
Decrease exchange rate by US$0.01 $ 28 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
b) Credit risk
Credit risk is the risk that a party to a financial instrument
will cause a financial loss for the Company by failing to discharge
an obligation.
The Company's accounts receivable are mainly with customers in
the crude oil and natural gas industry and are subject to normal
industry credit risks. The Company manages these risks by reviewing
its exposure to individual companies on a regular basis and where
appropriate, ensures that parental guarantees or letters of credit
are in place to minimize the impact in the event of default.
Substantially all of the Company's accounts receivables are due
within normal trade terms.
The Company is also exposed to possible losses in the event of
nonperformance by counterparties to derivative financial
instruments; however, the Company manages this credit risk by
entering into agreements with substantially all investment grade
financial institutions and other entities. At March 31, 2008, the
Company had net risk management assets of $6 million with specific
counterparties related to derivative financial instruments
(December 31, 2007 - $20 million).
c) Liquidity risk
Liquidity risk is the risk that the Company will encounter
difficulty in meeting obligations associated with financial
liabilities.
Management of liquidity risk requires the Company to maintain
sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating
activities, available credit facilities, and access to debt capital
markets, to meet obligations as they become due. Due to
fluctuations in the timing of the receipt and/or disbursement of
operating cash flows, the Company maintains adequate bank credit
facilities to provide liquidity.
The maturity dates for financial liabilities are as follows:
Less than 1 to less than 2 to less than Thereafter
1 year 2 years 5 years
----------------------------------------------------------------------------
Accounts payable $ 455 $ - $ - $ -
Accrued
liabilities $ 2,078 $ - $ - $ -
Risk management $ 1,362 $ 11 $ (40) $ 146
Long-term debt
(1) $ 40 $ 2,374 $ 1,982 $ 5,694
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or transaction
costs. No debt repayments are reflected for $1,182 million of revolving
bank credit facilities due to the extendable nature of the facilities.
11. COMMITMENTS
The Company has committed to certain payments as follows:
Remaining
2008 2009 2010 2011 2012 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 180 $ 163 $ 149 $ 123 $ 107 $ 1,099
Offshore equipment
operating leases (1) $ 98 $ 130 $ 118 $ 116 $ 94 $ 405
Offshore drilling (2) (3) $ 274 $ 187 $ 47 $ - $ - $ -
Asset retirement
obligations (4) $ 28 $ 4 $ 5 $ 4 $ 4 $ 4,484
Office leases $ 19 $ 26 $ 29 $ 22 $ 2 $ -
Electricity and other $ 126 $ 267 $ 162 $ 4 $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Offshore equipment operating leases are primarily comprised of
obligations related to floating production, storage and offtake vessels
("FPSO"). During 2006, the Company entered into an agreement to lease an
additional FPSO commencing in 2008, in connection with the planned
offshore development in Gabon, Offshore West Africa. During the initial
term, the total annual payments for the Gabon FPSO are estimated to be
US$50 million.
(2) During 2007, the Company entered into a one-year agreement for offshore
drilling services related to the Baobab Field in Cote d'Ivoire, Offshore
West Africa. The agreement is scheduled to commence in the second
quarter of 2008, on delivery of the rig. Estimated total payments of
US$100 million, after joint venture recoveries, have been included in
this table for the period 2008 - 2009.
(3) During 2007, the Company awarded contracts for a drilling rig and for
the construction of wellhead towers in connection with the planned
offshore development in Gabon, Offshore West Africa. Estimated total
payments of US$392 million have been included in this table for the
period 2008 - 2010.
(4) Amounts represent management's estimate of the future undiscounted
payments to settle asset retirement obligations related to resource
properties, facilities, and production platforms, based on current
legislation and industry operating practices. Amounts disclosed for
the period 2008 - 2012 represent the minimum required expenditures to
meet these obligations. Actual expenditures in any particular year may
exceed these minimum amounts.
In addition to the amounts disclosed above, the Company has
budgeted construction costs of approximately $1.1 billion to $1.3
billion for the remainder of 2008 related to the planned completion
of Phase 1 of the Horizon Project.
12. SEGMENTED INFORMATION
Offshore
North America North Sea West Africa
(millions of Three Months Three Months Three Months
Canadian dollars, Ended Ended Ended
unaudited) Mar 31 Mar 31 Mar 31
----------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
Segmented revenue 3,215 2,535 508 431 237 144
Less: royalties (405) (366) (1) (1) (43) (9)
----------------------------------------------------------------------------
Segmented revenue, net of
royalties 2,810 2,169 507 430 194 135
----------------------------------------------------------------------------
Segmented expenses
Production 451 422 112 116 21 22
Transportation and blending 493 365 3 4 - -
Depletion, depreciation and
amortization 566 560 86 107 34 40
Asset retirement obligation
accretion 11 9 6 8 - 1
Realized risk management
loss (gain) 417 (92) (1) 4 - -
----------------------------------------------------------------------------
Total segmented expenses 1,938 1,264 206 239 55 63
----------------------------------------------------------------------------
Segmented earnings before
the following 872 905 301 191 139 72
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Stock-based compensation
expense
Interest, net
Unrealized risk management
loss
Foreign exchange loss (gain)
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before taxes
Taxes other than income tax
Current income tax expense
Future income tax expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment
elimination
Midstream and other Total
(millions of Three Months Three Months Three Months
Canadian dollars, Ended Ended Ended
unaudited) Mar 31 Mar 31 Mar 31
----------------------------------------------------------------------------
2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
Segmented revenue 20 19 (13) (11) 3,967 3,118
Less: royalties - - - - (449) (376)
----------------------------------------------------------------------------
Segmented revenue, net of
royalties 20 19 (13) (11) 3,518 2,742
----------------------------------------------------------------------------
Segmented expenses
Production 5 6 (2) (1) 587 565
Transportation and blending - - (11) (10) 485 359
Depletion, depreciation and
amortization 2 2 - - 688 709
Asset retirement obligation
accretion - - - - 17 18
Realized risk management
loss (gain) - - - - 416 (88)
----------------------------------------------------------------------------
Total segmented expenses 7 8 (13) (11) 2,193 1,563
----------------------------------------------------------------------------
Segmented earnings before
the following 13 11 - - 1,325 1,179
----------------------------------------------------------------------------
Non-segmented expenses
Administration 43 60
Stock-based compensation
expense - 25
Interest, net 49 83
Unrealized risk management
loss 108 536
Foreign exchange loss (gain) 114 (27)
----------------------------------------------------------------------------
Total non-segmented
expenses 314 677
----------------------------------------------------------------------------
Earnings before taxes 1,011 502
Taxes other than income tax 49 63
Current income tax expense 155 70
Future income tax expense 80 100
----------------------------------------------------------------------------
Net earnings 727 269
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net additions to property, plant and equipment
Three Months Ended
Mar 31, 2008
----------------------------------------------------------------------------
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 663 $ 9 $ 672
North Sea 45 - 45
Offshore West Africa 94 (1) 93
Other - - -
Horizon Project (2) 941 - 941
Midstream 1 - 1
Head office 3 - 3
----------------------------------------------------------------------------
$ 1,747 $ 8 $ 1,755
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended
Mar 31, 2007
----------------------------------------------------------------------------
Non
Cash/Fair
Net Value Capitalized
Expenditures Changes (1) Costs
----------------------------------------------------------------------------
North America $ 998 $ 5 $ 1,003
North Sea 138 - 138
Offshore West Africa 36 - 36
Other 1 - 1
Horizon Project (2) 809 - 809
Midstream 2 - 2
Head office 5 - 5
----------------------------------------------------------------------------
$ 1,989 $ 5 $ 1,994
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Asset retirement obligations, future income tax adjustments related to
differences between carrying value and tax value, and other fair value
adjustments.
(2) Net expenditures for the Horizon Project also include capitalized
interest and stock-based compensation.
Property, plant and equipment Total assets
Mar 31 Dec 31 Mar 31 Dec 31
2008 2007 2008 2007
----------------------------------------------------------------------------
Segmented assets
North America $ 22,143 $ 22,033 $ 24,172 $ 23,617
North Sea 1,774 1,728 2,063 1,957
Offshore West Africa 1,244 1,188 1,387 1,354
Other 25 25 50 41
Horizon Project 9,592 8,651 9,662 8,740
Midstream 204 205 352 333
Head office 69 72 69 72
----------------------------------------------------------------------------
$ 35,051 $ 33,902 $ 37,755 $ 36,114
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capitalized interest
The Company capitalizes construction period interest based on
Horizon Project costs incurred and the Company's cost of borrowing.
Interest capitalization on a particular development phase ceases
once construction is substantially complete and this phase of the
Horizon Project is available for its intended use. For the three
months ended March 31, 2007, pre-tax interest of $111 million was
capitalized to the Horizon Project (March 31, 2007 - $71
million).
SUPPLEMENTARY INFORMATION
INTEREST COVERAGE RATIOS
The following financial ratios are provided in connection with
the Company's continuous offering of medium-term notes pursuant to
the short form prospectus dated September 2007. These ratios are
based on the Company's interim consolidated financial statements
that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the twelve month period ended March 31, 2008:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 5.2x
Cash flow from operations (2) 11.0x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net earnings plus income taxes and interest expense; divided by the sum
of interest expense and capitalized interest.
(2) Cash flow from operations plus current income taxes and interest
expense; divided by the sum of interest expense and capitalized
interest.
CONFERENCE CALL
A conference call will be held at 9:00 a.m. Mountain Time, 11:00
a.m. Eastern Time on Friday, May 9, 2008. The North American
conference call number is 1-877-461-2816 and the outside North
American conference call number is 001-416-695-9761. Please call in
about 10 minutes before the starting time in order to be patched
into the call. The conference call will also be broadcast live on
the internet and may be accessed through the Canadian Natural
website at www.cnrl.com.
A taped rebroadcast will be available until 6:00 p.m. Mountain
Time, Friday, May 16, 2008. To access the postview in North
America, dial 1-800-408-3053. Those outside of North America, dial
001-416-695-5800. The passcode to use is 3258848.
WEBCAST
This call is being webcast by Vcall and can be accessed on
Canadian Natural's website at
www.cnrl.com/investor_info/calendar.html.
The webcast is also being distributed over PrecisionIR's
Investor Distribution Network to both institutional and individual
investors. Investors can listen to the call through www.vcall.com
or by visiting any of the investor sites in PrecisionIR's
Individual Investor Network.
2008 SECOND QUARTER RESULTS
2008 second quarter results are scheduled for release prior to
market opening on Thursday, August 7, 2008. A conference call will
be held on that day at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern
Time.
Contacts: Canadian Natural Resources Limited Allan P. Markin
Chairman (403) 514-7777 (403) 514-7888 (FAX) Canadian Natural
Resources Limited John G. Langille Vice-Chairman (403) 514-7777
(403) 514-7888 (FAX) Canadian Natural Resources Limited Steve W.
Laut President and Chief Operating Officer (403) 514-7777 (403)
514-7888 (FAX) Canadian Natural Resources Limited Douglas A. Proll
Chief Financial Officer and Senior Vice-President, Finance (403)
514-7777 (403) 514-7888 (FAX) Canadian Natural Resources Limited
Corey B. Bieber Vice-President, Finance & Investor Relations
(403) 514-7777 (403) 514-7888 (FAX) Canadian Natural Resources
Limited 2500, 855 - 2nd Street S.W. Calgary, Alberta T2P 4J8 Email:
ir@cnrl.com Website: www.cnrl.com
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